UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

(Mark One)


þ		QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

FOR THE QUARTERLY PERIOD ENDED MARCH 31, ~~2007~~2008


o		TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

FOR THE TRANSITION PERIOD FROM TO .

Commission file number 1-31447

CENTERPOINT ENERGY, INC.

(Exact name of registrant as specified in its charter)


Texas		~~74-0694415~~
(State or other jurisdiction of incorporation or organization)		74-0694415 (I.R.S. Employer Identification No.)


1111 Louisiana Houston, Texas 77002
~~Houston, Texas 77002~~		(713) 207-1111
(Address and zip code of principal executive offices)		(Registrant’s telephone number, including area code)

Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yesþ Noo

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a ~~non-accelerated filer.~~smaller reporting company. See ~~definition~~the definitions of “large accelerated filer,” “accelerated ~~filer~~filer” and ~~large accelerated filer”~~“smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yeso Noþ

As of ~~May 1, 2007,~~March 31, 2008, CenterPoint Energy, Inc. had ~~320,787,541~~328,265,076 shares of common stock outstanding, excluding 166 shares held as treasury stock.

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION

From time to time we make statements concerning our expectations, beliefs, plans, objectives, goals, strategies, future events or performance and underlying assumptions and other statements that are not historical facts. These statements are “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995. Actual results may differ materially from those expressed or implied by these statements. You can generally identify our forward-looking statements by the words “anticipate,” “believe,” “continue,” “could,” “estimate,” “expect,” “forecast,” “goal,” “intend,” “may,” “objective,” “plan,” “potential,” “predict,” “projection,” “should,” “will,” or other similar words.

We have based our forward-looking statements on our management’s beliefs and assumptions based on information available to our management at the time the statements are made. We caution you that assumptions, beliefs, expectations, intentions and projections about future events may and often do vary materially from actual results. Therefore, we cannot assure you that actual results will not differ materially from those expressed or implied by our forward-looking statements.

The following are some of the factors that could cause actual results to differ materially from those expressed or implied in forward-looking statements:

	•		the ~~timing and amount of our recovery~~resolution of the true-up ~~components,~~proceedings, including, in particular, the results of appeals to the courts ~~of determinations on~~regarding rulings obtained to date;

	•		state and federal legislative and regulatory actions or developments, including deregulation, re-regulation, environmental regulations, including regulations related to global climate change, and changes in or application of laws or regulations applicable to the various aspects of our business;

	•		timely and appropriate rate actions and increases, allowing recovery of costs and a reasonable return on investment;

	•		cost overruns on major capital projects that cannot be recouped in prices;

	•		industrial, commercial and residential growth in our service territory and changes in market demand and demographic patterns;

	•		the timing and extent of changes in commodity prices, particularly natural gas;

	•		~~changes in interest rates or rates of inflation;~~

	•		~~weather variations and other natural phenomena;~~

	•		the timing and extent of changes in the supply of natural gas;

	•		the timing and extent of changes in natural gas basis differentials;

	•		weather variations and other natural phenomena;

	•		changes in interest rates or rates of inflation;

	•		commercial bank and financial market conditions, our access to capital, the cost of such capital, and the results of our financing and refinancing efforts, including availability of funds in the debt capital markets;

	•		actions by rating agencies;

	•		effectiveness of our risk management activities;

	•		inability of various counterparties to meet their obligations to us;

	•		non-payment for our services due to financial distress of our customers, including Reliant Energy, Inc. (RRI);

	•		the ability of RRI and its subsidiaries to satisfy their other obligations to us, including indemnity obligations, or in connection with the contractual arrangements pursuant to which we are their guarantor;

CENTERPOINT ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS —– (continued)
(Millions of Dollars)
(Unaudited)

LIABILITIES AND SHAREHOLDERS’ EQUITY


	December 31,			March 31,			December 31,			March 31,
	2006			2007			2007			2008
Current Liabilities:
Short-term borrowings	$	187		$	337		$	232		$	200
Current portion of transition bond long-term debt		147			152			159			186
Current portion of other long-term debt		1,051			993			1,156			724
Indexed debt securities derivative		372			331			261			211
Accounts payable		1,010			724			726			779
Taxes accrued		364			325			316			269
Interest accrued		159			133			170			145
Non-trading derivative liabilities		141			48			61			33
Accumulated deferred income taxes, net		316			311			350			367
Other		474			412			360			370

Total current liabilities		4,221			3,766			3,791			3,284


Other Liabilities:
Accumulated deferred income taxes, net		2,323			2,234			2,235			2,229
Unamortized investment tax credits		39			37			31			29
Non-trading derivative liabilities		80			38			14			4
Benefit obligations		545			535			499			493
Regulatory liabilities		792			809			828			795
Other		275			322			300			275

Total other liabilities		4,054			3,975			3,907			3,825


Long-term Debt:
Transition bonds		2,260			2,183			2,101			2,485
Other		5,542			5,635			6,263			6,061

Total long-term debt		7,802			7,818			8,364			8,546


Commitments and Contingencies (Note 10)

Shareholders’ Equity:
Common stock (313,651,639 shares and 320,537,680 shares outstanding at December 31, 2006 and March 31, 2007, respectively)		3			3
Common stock (322,718,785 shares and 328,265,076 shares outstanding at December 31, 2007 and March 31, 2008, respectively)								3			3
Additional paid-in capital		2,977			3,010			3,023			3,041
Accumulated deficit		(1,355	)		(1,277	)		(1,172	)		(1,109	)
Accumulated other comprehensive loss		(69	)		(89	)		(44	)		(55	)

Total shareholders’ equity		1,556			1,647			1,810			1,880


Total Liabilities and Shareholders’ Equity	$	17,633		$	17,206		$	17,872		$	17,535

CENTERPOINT ENERGY, INC. AND SUBSIDIARIES

CONDENSED STATEMENTS OF CONSOLIDATED CASH FLOWS

(Millions of Dollars)

(Unaudited)


	Three Months Ended March 31,						Three Months Ended March 31,
	2006			2007			2007			2008
Cash Flows from Operating Activities:
Net income	$	88		$	130		$	130		$	123
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		140			145			145			158
Amortization of deferred financing costs		14			19			19			7
Deferred income taxes		6			(11	)		(13	)		27
Investment tax credit		(2	)		(2	)
Unrealized loss on Time Warner investment		14			44			44			54
Unrealized gain on indexed debt securities		(10	)		(41	)		(41	)		(50	)
Changes in other assets and liabilities:
Accounts receivable and unbilled revenues, net		472			16			16			(84	)
Inventory		129			217			217			327
Taxes receivable		53			—
Accounts payable		(534	)		(222	)		(222	)		56
Fuel cost over recovery		63			23			23			29
Non-trading derivatives, net		19			18			18			28
Margin deposits, net		(79	)		52			52			29
Interest and taxes accrued		(27	)		(65	)		(65	)		(72	)
Net regulatory assets and liabilities		23			22			22			14
Other current assets		7			25			25			34
Other current liabilities		(47	)		(85	)		(85	)		(63	)
Other assets		14			(4	)		(4	)		(15	)
Other liabilities		(51	)		(34	)		(34	)		(47	)
Other, net		23			17			17			12

Net cash provided by operating activities		315			264			264			567


Cash Flows from Investing Activities:
Capital expenditures		(186	)		(399	)		(399	)		(187	)
Decrease (increase) in restricted cash of transition bond companies		(7	)		5			5			(13	)
Increase in notes receivable from unconsolidated affiliates								—			(2	)
Investment in unconsolidated affiliates								—			(105	)
Other, net		(8	)		(9	)		(9	)		(5	)

Net cash used in investing activities		(201	)		(403	)		(403	)		(312	)


Cash Flows from Financing Activities:
Increase in short-term borrowings, net		—			150
Increase (decrease) in short-term borrowings, net								150			(32	)
Long-term revolving credit facilities, net		(3	)		—			—			(231	)
Proceeds from commercial paper, net								—			35
Proceeds from long-term debt		—			400			400			488
Payments of long-term debt		(27	)		(434	)		(434	)		(515	)
Debt issuance costs		(2	)		(6	)		(6	)		—
Payment of common stock dividends		(47	)		(54	)		(54	)		(60	)
Proceeds from issuance of common stock, net		3			13			13			1
Other, net		1			3			3			—

Net cash provided by (used in) financing activities		(75	)		72			72			(314	)


Net Increase (Decrease) in Cash and Cash Equivalents		39			(67	)
Net Decrease in Cash and Cash Equivalents								(67	)		(59	)
Cash and Cash Equivalents at Beginning of Period		74			127			127			129

Cash and Cash Equivalents at End of Period	$	113		$	60		$	60		$	70


Supplemental Disclosure of Cash Flow Information:
Cash Payments:
Interest, net of capitalized interest	$	125		$	177		$	177		$	173
Income taxes (refunds), net		(1	)		34
Income taxes, net								34			39

CENTERPOINT ENERGY, INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(1) Background and Basis of Presentation

General.Included in this Quarterly Report on Form 10-Q (Form 10-Q) of CenterPoint Energy, Inc. are the condensed consolidated interim financial statements and notes (Interim Condensed Financial Statements) of CenterPoint Energy, Inc. and its subsidiaries (collectively, CenterPoint Energy, or the Company). The Interim Condensed Financial Statements are unaudited, omit certain financial statement disclosures and should be read with the Annual Report on Form 10-K of CenterPoint Energy for the year ended December 31, ~~2006~~2007 (CenterPoint Energy Form 10-K).

Background.CenterPoint Energy, Inc. is a public utility holding company, created on August 31, 2002 as part of a corporate restructuring of Reliant Energy, Incorporated (Reliant Energy) that implemented certain requirements of the Texas Electric Choice Plan (Texas electric restructuring law).

company. The Company’s operating subsidiaries own and operate electric transmission and distribution facilities, natural gas distribution facilities, interstate pipelines and natural gas gathering, processing and treating facilities. As of March 31, ~~2007,~~2008, the Company’s indirect wholly owned subsidiaries included:

	•		CenterPoint Energy Houston Electric, LLC (CenterPoint Houston), which engages in the electric transmission and distribution business in a 5,000-square mile area of the Texas Gulf Coast that includes Houston; and

	•		CenterPoint Energy Resources Corp. (CERC Corp., and, together with its subsidiaries, CERC), which owns and operates natural gas distribution systems in six states. ~~Wholly owned subsidiaries~~Subsidiaries of CERC own interstate natural gas pipelines and gas gathering systems and provide various ancillary services. ~~Another~~A wholly owned subsidiary of CERC Corp. offers variable and fixed-price physical natural gas supplies primarily to commercial and industrial customers and electric and gas utilities.

Basis of Presentation.The preparation of financial statements in conformity with ~~accounting principles~~ generally accepted ~~in the United States of America~~accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, ~~and~~ disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

The Company’s Interim Condensed Financial Statements reflect all normal recurring adjustments that are, in the opinion of management, necessary to present fairly the financial position, results of operations and cash flows for the respective periods. Amounts reported in the Company’s Condensed Statements of Consolidated Income are not necessarily indicative of amounts expected for a full-year period due to the effects of, among other things, (a) seasonal fluctuations in demand for energy and energy services, (b) changes in energy commodity prices, (c) timing of maintenance and other expenditures and (d) acquisitions and dispositions of businesses, assets and other interests. In addition, business segment information for the three months ended March 31, 2006 has been recast to conform to the 2007 presentation due to the change in reportable business segments in the fourth quarter of 2006. The business segment detail revised as a result of the new reportable business segments did not affect consolidated operating income for any period presented.

For a description of the Company’s reportable business segments, reference is made to Note 13.

(2) New Accounting Pronouncements

In ~~July 2006,~~April 2007, the Financial Accounting Standards Board (FASB) issued Staff Position No. FIN 39-1, “Amendment of FASB Interpretation No. ~~48, “Accounting for Uncertainty in Income Taxes — an Interpretation of FASB Statement No. 109”~~39,” (FIN ~~48).~~39-1) which permits companies that enter into master netting arrangements to offset cash collateral receivables or payables with net derivative positions under certain circumstances. The Company adopted FIN 48 clarifies the accounting for uncertain income tax positions and requires the Company to recognize management’s best estimate of the impact of a tax position if it is considered “more likely than not”, as defined in Statement of Financial Accounting Standards (SFAS) No. 5, “Accounting for Contingencies”, of being sustained on audit based solely on the technical merits of the position. FIN 48 also provides guidance on derecognition, classification, interest

~~and penalties, accounting in interim periods, disclosure, and transition. The cumulative effect of adopting FIN 48 as of~~39-1 effective January 1, ~~2007 was an approximately $2 million credit to accumulated deficit. The Company recognizes interest and penalties as a component of income taxes.~~

The implementation of FIN 48 also impacted other balance sheet accounts. The balance sheet as of January 1, 2007, upon adoption, would have reflected approximately $72 million of total unrecognized tax benefits in “Other Liabilities.” This amount includes $48 million reclassified from accumulated deferred income taxes to the liability for uncertain tax positions. The remaining $24 million represents amounts previously accrued for uncertain tax positions that, if recognized, would reduce the effective income tax rate. In addition to these amounts, the Company, at January 1, 2007, accrued approximately $4 million for the payment of interest for these uncertain tax positions. The amount of unrecognized tax benefits was not materially different as of March 31, 2007.

~~The Company’s consolidated federal income tax returns and major state tax returns have been settled through the 1996 tax year.~~

In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements” (SFAS No. 157). SFAS No. 157 establishes a framework for measuring fair value and requires expanded disclosure about the information used to measure fair value. The statement applies whenever other statements require or permit assets or liabilities to be measured at fair value. The statement does not expand the use of fair value accounting in any new circumstances and is effective for the Company for the year ended December 31, 2008 and ~~for interim periods included in that year,~~began netting the cash collateral receivables and payables and also its derivative assets and liabilities with ~~early adoption encouraged. The Company is currently evaluating~~ the ~~effect of adoption of this new standard on its financial position, results of operations and cash flows.~~same counterparty subject to master netting agreements.

In February 2007, the FASB issued ~~SFAS~~Statement of Financial Accounting Standard (SFAS) No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities, including an amendment of FASB Statement No. 115” (SFAS No. 159). SFAS No. 159 permits the Company to choose, at specified election dates, to measure eligible items at fair value (the “fair value option”). The Company would report unrealized gains and losses on items for which the fair value option has been elected in earnings at each subsequent reporting period. This accounting

standard is effective as of the beginning of the first fiscal year that begins after November 15, ~~2007.~~2007 but is not required to be applied. The Company currently has no plans to apply SFAS No. 159.

In December 2007, the FASB issued SFAS No. 141 (Revised 2007),“Business Combinations” (SFAS No. 141R).SFAS No. 141R will significantly change the accounting for business combinations. Under SFAS No. 141R, an acquiring entity will be required to recognize all the assets acquired and liabilities assumed in a transaction at the acquisition date fair value with limited exceptions. SFAS No. 141R also includes a substantial number of new disclosure requirements and applies prospectively to business combinations for which the acquisition date is ~~currently evaluating~~on or after the ~~effect~~beginning of the first annual reporting period beginning on or after December 15, 2008. As the provisions of SFAS No. 141R are applied prospectively, the impact to the Company cannot be determined until applicable transactions occur.

In December 2007, the FASB issued SFAS No. 160,“Noncontrolling Interests in Consolidated Financial Statements — An Amendment of ARB No. 51” (SFAS No. 160). SFAS No. 160 establishes new accounting and reporting standards for the noncontrolling interest in a subsidiary and for the deconsolidation of a subsidiary. This accounting standard is effective for fiscal years, and interim periods within those fiscal years, beginning on or after December 15, 2008. The Company will adopt SFAS No. 160 as of January 1, 2009. The Company expects that the adoption of ~~this new standard~~SFAS No. 160 will not have a material impact on its financial position, results of operations ~~and~~or cash flows.

Effective January 1, 2008, the Company adopted SFAS No. 157, “Fair Value Measurements” (SFAS No. 157), which requires additional disclosures about the Company’s financial assets and liabilities that are measured at fair value. FASB Staff Position No. FAS 157-2 delays the effective date for SFAS No. 157 for nonfinancial assets and liabilities, except for items that are recognized or disclosed at fair value in the financial statements on a recurring basis, to fiscal years, and interim periods within those fiscal years, beginning after November 15, 2008. As defined in SFAS No. 157, fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. Where available, fair value is based on observable market prices or parameters or derived from such prices or parameters. Where observable prices or inputs are not available, valuation models are applied. These valuation techniques involve some level of management estimation and judgment, the degree of which is dependent on the price transparency for the instruments or market and the instruments’ complexity for disclosure purposes. Beginning in January 2008, assets and liabilities recorded at fair value in the Condensed Consolidated Balance Sheet are categorized based upon the level of judgment associated with the inputs used to measure their value. Hierarchical levels, as defined in SFAS No. 157 and directly related to the amount of subjectivity associated with the inputs to fair valuations of these assets and liabilities, are as follows:

Level 1: Inputs are unadjusted quoted prices in active markets for identical assets or liabilities at the measurement date. The types of assets carried at Level 1 fair value generally are financial derivatives, investments and equity securities listed in active markets.

Level 2: Inputs, other than quoted prices included in Level 1, are observable for the asset or liability, either directly or indirectly. Level 2 inputs include quoted prices for similar instruments in active markets, and inputs other than quoted prices that are observable for the asset or liability. Fair value assets and liabilities that are generally included in this category are derivatives with fair values based on inputs from actively quoted markets.

Level 3: Inputs are unobservable inputs for the asset or liability, and include situations where there is little, if any, market activity for the asset or liability. In certain cases, the inputs used to measure fair value may fall into different levels of the fair value hierarchy. In such cases, the level in the fair value hierarchy within which the fair value measurement in its entirety falls has been determined based on the lowest level input that is significant to the fair value measurement in its entirety. The Company’s assessment of the significance of a particular input to the fair value measurement in its entirety requires judgment, and considers factors specific to the asset. Generally, assets and liabilities carried at fair value and included in this category are financial derivatives.

The following table presents information about the Company’s assets and liabilities (including derivatives that are presented net) measured at fair value on a recurring basis as of March 31, 2008, and indicates the fair value hierarchy of the valuation techniques utilized by the Company to determine such fair value.


	Quoted Prices in		Significant Other		Significant
	Active Markets		Observable		Unobservable					Balance
	for Identical Assets		Inputs		Inputs		Netting			as of
	(Level 1)		(Level 2)		(Level 3)		Adjustments (1)			March 31, 2008
					(in millions)
Assets
Corporate equities	$	305	$	—	$	—	$	—		$	305
Investments		74		—		—		(1	)		73
Derivative assets		1		103		4		(27	)		81

Total assets	$	380	$	103	$	4	$	(28	)	$	459


Liabilities
Indexed debt securities derivative	$	—	$	211	$	—	$	—		$	211
Derivative liabilities		3		60		2		(28	)		37

Total liabilities	$	3	$	271	$	2	$	(28	)	$	248


(1)		Amounts represent the impact of legally enforceable master netting agreements that allow the Company to settle positive and negative positions and also cash collateral held or placed with the same counterparties.

The following table presents additional information about assets or liabilities, including derivatives that are measured at fair value on a recurring basis for which the Company has utilized Level 3 inputs to determine fair value, for the three months ended March 31, 2008:


	Fair Value Measurements
	Using Significant
	Unobservable Inputs
	(Level 3)
	Derivatives, net
	(in millions)
Beginning balance as of January 1, 2008	$	(3	)
Total gains or losses (realized and unrealized):
Included in earnings		6
Included in other comprehensive loss		—
Net transfers into level 3		—
Purchases, sales, other settlements, net		(1	)

Ending balance as of March 31, 2008	$	2


The amount of total gains or losses for the period included in earnings attributable to the change in unrealized gains or losses relating to assets still held at the reporting date	$	1

(3) Employee Benefit Plans

The Company’s net periodic cost includes the following components relating to pension and postretirement benefits:


	Three Months Ended March 31,												Three Months Ended March 31,
	2006						2007						2007						2008
	Pension			Postretirement			Pension			Postretirement			Pension			Postretirement			Pension			Postretirement
	Benefits			Benefits			Benefits			Benefits			Benefits			Benefits			Benefits			Benefits
	(in millions)															(in millions)
Service cost	$	9		$	1		$	9		$	—		$	9		$	—		$	8		$	—
Interest cost		25			6			25			7			25			7			25			7
Expected return on plan assets		(35	)		(3	)		(37	)		(3	)		(37	)		(3	)		(37	)		(3	)
Amortization of prior service cost		(2	)		—			(2	)		1			(2	)		1			(2	)		1
Amortization of net loss		12			—			9			—			9			—			6			—
Amortization of transition obligation		—			2			—			2			—			2			—			2
Benefit enhancement		8			1			—			—

Net periodic cost	$	17		$	7		$	4		$	7		$	4		$	7		$	—		$	7

(4) Regulatory Matters

(a) Recovery of True-Up Balance

In March 2004, CenterPoint Houston filed its true-up application with the Public Utility Commission of Texas (Texas Utility Commission), requesting recovery of $3.7 billion, excluding interest, as allowed under the Texas Electric Choice Plan (Texas electric restructuring ~~law.~~law). In December 2004, the Texas Utility Commission issued its final order (True-Up Order) allowing CenterPoint Houston to recover a true-up balance of approximately $2.3 billion, which included interest through August 31, 2004, and ~~providing~~provided for adjustment of the amount to be recovered to include interest on the balance until recovery, along with the principal portion of additional excess mitigation credits (EMCs) returned to customers after August 31, 2004 and in certain other ~~matters.~~respects.

CenterPoint Houston and other parties filed appeals of the True-Up Order to a district court in Travis County, Texas. In August 2005, ~~the~~that court issued its ~~final~~ judgment on the various appeals. In its judgment, the ~~court affirmed most aspects of the True-Up Order, but reversed two of the Texas Utility Commission’s rulings.~~district court:

	•		reversed the Texas Utility Commission’s ruling that had denied recovery of a portion of the capacity auction true-up amounts;

	•		reversed the Texas Utility Commission’s ruling that precluded CenterPoint Houston from recovering the interest component of the EMCs paid to retail electric providers; and

	•		affirmed the True-Up Order in all other respects.

The ~~judgment~~district court’s decision would have had the effect of restoring approximately $650 million, plus interest, of the $1.7 billion the Texas Utility Commission had disallowed from CenterPoint Houston’s initial request.

CenterPoint Houston and other parties appealed the district court’s ~~judgment. Oral arguments before~~judgment to the Texas ~~3rd~~Third Court of Appeals, ~~were held~~which issued its decision in ~~January 2007, but~~December 2007. In its decision, the court of appeals:

	•		reversed the district court’s judgment to the extent it restored the capacity auction true-up amounts;

	•		reversed the district court’s judgment to the extent it upheld the Texas Utility Commission’s decision to allow CenterPoint Houston to recover EMCs paid to Reliant Energy, Inc. (RRI);

	•		ordered that the tax normalization issue described below be remanded to the Texas Utility Commission as requested by the Texas Utility Commission; and

	•		affirmed the district court’s judgment in all other respects.

CenterPoint Houston and two other parties filed motions for rehearing with the court of appeals. On April 17, 2008, the court of appeals denied those motions and reissued substantially the same opinion as it had rendered in December 2007. CenterPoint Houston now plans to seek further review by the Texas Supreme Court. Although the Company and CenterPoint Houston believe that CenterPoint Houston’s true-up request is consistent with applicable statutes and regulations and, accordingly, that it is reasonably possible that it will be successful in its further appeal, the Company can provide no assurance as to the ultimate court rulings on the issues to be considered in the appeal or with respect to the ultimate decision by the Texas Utility Commission on the tax normalization issue described below.

To reflect the impact of the True-Up Order, in 2004 and 2005 the Company recorded a ~~decision is not expected for several months.~~net after-tax extraordinary loss of $947 million. No amounts related to the district court’s judgment or the decision of the court of appeals have been recorded in the Company’s consolidated financial statements. However, if the court of appeals

decision is not reversed or modified as a result of further review by the Texas Supreme Court, the Company anticipates that it would be required to record an additional loss to reflect the court of appeals decision. The amount of that loss would depend on several factors, including ultimate resolution of the tax normalization issue described below and the calculation of interest on any amounts CenterPoint Houston ultimately is authorized to recover or is required to refund beyond the amounts recorded based on the True-up Order, but could range from $130 million to $350 million plus interest subsequent to December 31, 2007.

~~Among the issues raised in CenterPoint Houston’s appeal of~~In the True-Up Order, is the Texas Utility ~~Commission’s reduction of~~Commission reduced CenterPoint Houston’s stranded cost recovery by approximately $146 million, which was included in the extraordinary loss discussed above, for the present value of certain deferred tax benefits associated with its former electric generation assets. ~~Such reduction was considered in the Company’s recording of an after-tax extraordinary loss of $977 million in the last half of 2004.~~ The Company believes that the Texas Utility Commission based its order on proposed regulations issued by the Internal Revenue Service (IRS) in March 2003 ~~related to those tax benefits. Those proposed regulations~~which would have allowed utilities owning assets that were deregulated before March 4, 2003 to make a retroactive election to pass the benefits of Accumulated Deferred Investment Tax Credits (ADITC) and Excess Deferred Federal Income Taxes (EDFIT) back to customers. However, ~~in December 2005,~~ the IRS subsequently withdrew those proposed normalization regulations and ~~issued new proposed~~in March 2008 adopted final regulations that dowould not ~~include the provision allowing a retroactive election~~permit CenterPoint Houston to pass the tax benefits back to ~~customers.~~customers without creating normalization violations. In addition, the Company received a ~~May 2006~~ Private Letter Ruling (PLR) ~~issued to a Texas utility on facts similar to CenterPoint Houston’s,~~from the IRS ~~without referencing its proposed~~in August 2007, prior to adoption of the final regulations, ~~ruled~~ that ~~a normalization violation would occur if ADITC and EDFIT were required to be returned to customers. CenterPoint Houston has requested a PLR asking the IRS whether~~confirmed that the Texas Utility Commission’s order reducing CenterPoint Houston’s stranded cost recovery by $146 million for ADITC and EDFIT would cause a normalization ~~violation. If the IRS determines that such reduction would cause a normalization violation~~violations with respect to the ADITC and EDFIT.

If the Texas Utility Commission’s order relating to ~~such~~the ADITC reduction is not reversed or otherwise modified on remand so as to eliminate the normalization violation, the IRS could require the Company to pay an amount equal to CenterPoint Houston’s unamortized ADITC balance as of the date that the normalization violation is deemed to have occurred. In addition, ~~if a normalization violation with respect to EDFIT is deemed to have occurred and the Texas Utility Commission’s order relating to such reduction is not reversed or otherwise modified,~~ the IRS could deny CenterPoint Houston the ability to elect accelerated tax depreciation benefits beginning in the taxable year that the normalization violation is deemed to have occurred. ~~If a normalization violation should ultimately be found to exist, it~~Such treatment, if required by the IRS, could have a material adverse impact on the Company’s results of operations, financial condition and cash ~~flows.~~flows in addition to any potential loss resulting from final resolution of the True-Up Order. However, the Company and CenterPoint Houston ~~are vigorously pursuing the appeal~~will continue to pursue a favorable resolution of this issue ~~and will seek other relief from~~through the ~~Texas Utility Commission to avoid a normalization violation.~~appellate or administrative process. Although the Texas Utility Commission has not previously required a company subject to its jurisdiction to take action that would result in a normalization violation, no prediction can be made as to the ultimate action the Texas Utility Commission may take on this ~~issue.~~issue on remand.

The Texas electric restructuring law allowed the amounts awarded to CenterPoint Houston in the Texas Utility Commission’s True-Up Order to be recovered either through the issuance of transition bonds or through implementation of a competition transition charge (CTC) or both. Pursuant to a financing order issued by the Texas Utility Commission in March 2005 and affirmed ~~in August 2005~~ by a Travis County district court, in December 2005 a subsidiary of CenterPoint Houston issued $1.85 billion in transition bonds with interest rates ranging from ~~4.84 percent~~4.84% to ~~5.30 percent~~5.30% and final maturity dates ranging from February 2011 to August 2020. Through issuance of the transition bonds, CenterPoint Houston recovered approximately $1.7 billion of the true-up balance determined in the True-Up Order plus interest through the date on which the bonds were issued.

In July 2005, CenterPoint Houston received an order from the Texas Utility Commission allowing it to implement a ~~competition transition charge (CTC)~~CTC designed to collect ~~approximately~~the remaining $596 million from the True-Up Order over 14 years plus

interest at an annual rate of ~~11.075 percent~~11.075% (CTC Order). The CTC Order ~~authorizes~~authorized CenterPoint Houston to impose a charge on retail electric providers to recover the portion of the true-up balance not ~~covered by the~~recovered through a financing order. The CTC Order also ~~allows~~allowed CenterPoint Houston to collect approximately $24 million of rate case expenses over three years without a return through a separate tariff rider (Rider RCE). CenterPoint Houston implemented the CTC and Rider RCE effective September 13, 2005 and began recovering approximately $620 million. ~~Effective September 13, 2005, the~~The return on the CTC portion of the true-up balance iswas included in CenterPoint Houston’s tariff-based ~~revenues.~~revenues beginning September 13, 2005. Effective August 1, 2006, the interest rate on the unrecovered balance of the CTC was reduced from 11.075% to a weighted average cost of capital of 8.06% pursuant to a revised rule adopted by the Texas Utility Commission in June 2006.

Certain parties appealed the CTC Order to a district court in Travis County. In May 2006, the district court issued a judgment reversing the CTC Order in three respects. First, the court ruled that the Texas Utility Commission had improperly relied on provisions of its rule dealing with the interest rate applicable to CTC

amounts. The district court reached that conclusion based on ~~the grounds~~its belief that the Texas Supreme Court had previously invalidated that entire section of the rule. The 11.075% interest rate in question was applicable from the implementation of the CTC Order on September 13, 2005 until August 1, 2006, the effective date of the implementation of a new CTC in compliance with the revised rule discussed above. Second, the district court reversed the Texas Utility Commission’s ruling that allows CenterPoint Houston to recover through the Rider RCE the costs (approximately $5 million) for a panel appointed by the Texas Utility Commission in connection with the valuation of ~~the Company’s~~ electric generation assets. Finally, the district court accepted the contention of one party that the CTC should not be allocated to retail customers that have switched to new on-site generation. The Texas Utility Commission and CenterPoint Houston disagree with the district court’s conclusions and, in May 2006, appealed the judgment to the Texas ~~3rd~~Third Court of Appeals, and if required, ~~plan~~CenterPoint Houston plans to seek further review from the Texas Supreme Court. All briefs in the appeal have been ~~filed. Oral~~filed, and oral arguments were held in December 2006. Pending completion of judicial review and any action required by the Texas Utility Commission following a remand from the courts, the CTC remains in effect. The 11.075 percent interest rate in question was applicable from the implementation of the CTC Order on September 13, 2005 until August 1, 2006, the effective date of the implementation of a new CTC in compliance with the new rule discussed below. The ultimate outcome of this matter cannot be predicted at this time. However, the Company does not expect the disposition of this matter to have a material adverse effect on the Company’s or CenterPoint Houston’s financial condition, results of operations or cash flows.

In June 2006, the Texas Utility Commission adopted the revised rule governing the carrying charges on unrecovered true-up balances as recommended by its staff (Staff). The rule, which applies to CenterPoint Houston, reduced the allowed interest rate on the unrecovered CTC balance prospectively from 11.075 percent to a weighted average cost of capital of 8.06 percent. The annualized impact on operating income is a reduction of approximately $18 million per year for the first year with lesser impacts in subsequent years. In July 2006, CenterPoint Houston made a compliance filing necessary to implement the rule changes effective August 1, 2006 per the settlement agreement entered into in connection with CenterPoint Houston’s rate proceeding.

During the three months ended March 31, ~~2006~~2007 and ~~2007,~~2008, CenterPoint Houston recognized approximately ~~$16~~$11 million and ~~$11~~$5 million, respectively, in operating income from the ~~CTC.~~CTC, which was terminated in February 2008 when the transition bonds described below were issued. Additionally, during the three months ended March 31, ~~2006~~2007 and ~~2007,~~2008, CenterPoint Houston recognized approximately $2$3 million and $3$2 million, respectively, of the allowed equity return not previously recorded.

During the 2007 legislative session, the Texas legislature amended statutes prescribing the types of true-up balances that can be securitized by utilities and authorized the issuance of transition bonds to recover the balance of the CTC. In June 2007, CenterPoint Houston filed a request with the Texas Utility Commission for a financing order that would allow the securitization of the remaining balance of the CTC, adjusted to refund certain unspent environmental retrofit costs and to recover the amount of the final fuel reconciliation settlement. CenterPoint Houston reached substantial agreement with other parties to this proceeding, and a financing order was approved by the Texas Utility Commission in September 2007. In February 2008, a new special purpose subsidiary of CenterPoint Houston issued approximately $488 million of transition bonds pursuant to the financing order in two tranches with interest rates of 4.192% and 5.234% and final maturity dates of February 2020 and February 2023, respectively. Contemporaneously with the issuance of those bonds, the CTC was terminated and a transition charge was implemented.

As of March 31, ~~2007,~~2008, the Company had not recorded an allowed equity return of ~~$231~~$218 million on CenterPoint Houston’s true-up balance because such return will be recognized as it is recovered in rates.

(b) ~~Final Fuel Reconciliation~~

The results of the Texas Utility Commission’s final decision related to CenterPoint Houston’s final fuel reconciliation were a component of the True-Up Order. CenterPoint Houston has appealed certain portions of the True-Up Order involving a disallowance of approximately $67 million relating to the final fuel reconciliation in 2003 plus interest of $10 million. CenterPoint Houston has fully reserved for the disallowance and related interest accrual. A judgment was entered by a Travis County district court in May 2005 affirming the Texas Utility Commission’s decision. CenterPoint Houston filed an appeal to the Texas 3rd Court of Appeals in June 2005, but in April 2006, that court issued a judgment affirming the Texas Utility Commission’s decision. CenterPoint Houston filed an appeal with the Texas Supreme Court in August 2006, but in February 2007, CenterPoint Houston made a filing with the Texas Supreme Court indicating that the parties had reached a tentative settlement of the appeal and requesting the Texas Supreme Court to abate the appeal in order to allow the Texas Utility Commission to review the settlement. The Texas Supreme Court granted the abatement of the appeal, and CenterPoint Houston has filed the settlement agreement with the Texas Utility Commission, which has established a procedural schedule for interventions, any requests for a hearing and submissions of a proposed order. If the Texas Utility Commission does

not approve the agreement or modifies the agreement in a manner unacceptable to CenterPoint Houston, CenterPoint Houston would be entitled to ask the Texas Supreme Court to reinstate the appeal. If the Texas Utility Commission approves the agreement, the parties will request the Texas Supreme Court to set aside the lower court decisions and remand the case for entry of an order approving that settlement. As of March 31, 2007, the Company has not recorded any amounts related to this pending settlement.

~~(c) Refund of Environmental Retrofit Costs~~

The True-Up Order allowed recovery of approximately $699 million of environmental retrofit costs related to CenterPoint Houston’s generation assets. The sale of CenterPoint Houston’s interest in its generation assets was completed in early 2005. The True-Up Order required CenterPoint Houston to provide evidence by January 31, 2007 that the entire $699 million was actually spent by December 31, 2006 on environmental programs. The Texas Utility Commission will determine the appropriate manner to return to customers any unused portion of these funds, including interest on the funds and on stranded costs attributable to the environmental costs portion of the stranded costs recovery. In January 2007, the Company was notified by the successor in interest to CenterPoint Houston’s generation assets that, as of December 31, 2006, it had only spent approximately $664 million. On January 31, 2007, CenterPoint Houston made the required filing with the Texas Utility Commission, identifying approximately $35 million in unspent funds to be refunded to customers along with approximately $7 million of interest and requesting permission to refund these amounts through a reduction to the CTC. Such amounts were recorded as regulatory liabilities as of December 31, 2006. Certain parties have requested a hearing in this docket, and the Texas Utility Commission has requested briefing on whether the $699 million included amounts spent by the successor in interest to CenterPoint Energy’s generating assets after CenterPoint Energy sold its interest in those assets. At this time, the Company cannot predict whether the Texas Utility Commission will approve CenterPoint Houston’s request.

~~(d)~~ Rate Cases

~~Arkansas.~~Texas.In ~~January 2007,~~March 2008, CERC Corp.’s natural gas distribution business (Gas Operations) filed ~~an application with the Arkansas Public Service Commission (APSC)~~a request to change its natural gas distribution rates. This filing seeks approval to change the base rate portion of a customer’s natural gas bill, which makes up about 30 percent of the total bill and covers the cost of distributing natural gas. The filing does not apply to the Gas Supply Rate (GSR), which makes up the remaining approximately 70 percent of the bill. Through the GSR, Gas Operations passes through to its customers the actual cost it pays for the natural gas it purchases for use by its customers without any mark-up. In a separate filing in January 2007, Gas Operations reduced the GSR by approximately 9 percent. The APSC approved this GSR filing in January 2007.

~~The filing seeks approval by the APSC of new base~~ rates that would go into effect later this year and would generate approximately $51 million in additional revenue on an annual basis. The effect on individual monthly bills would vary depending on natural gas use and customer class. As part of the base rate filing, Gas Operations is also proposing a mechanism that, if approved, would help stabilize revenues, eliminate the potential conflict between its efforts to earn a reasonable return on invested capital while promoting energy efficiency initiatives, and minimize the need for future rate cases. As part of the revenue stabilization mechanism, Gas Operations proposed to reduce the requested return on equity by 35 basis points which would reduce the base rate increase by $1 million. The mechanism would be in place through December 31, 2010.

~~Texas.~~In September 2006, Gas Operations filed Statements of Intent (SOI) with 47 cities in its Texas coast service territory to increase miscellaneous service charges and to allow recovery of the costs of financial hedging transactions through its purchased gas cost adjustment. In November 2006, these changes became effective as all 47 cities either approved the filings or took no action, thereby allowing rates to go into effect by operation of law. In December 2006, Gas Operations filed a SOI with the Railroad Commission of Texas (Railroad Commission) ~~seeking~~and the 47 cities in its Texas Coast service territory, an area consisting of approximately 230,000 customers in cities and communities on the outskirts of Houston. The request seeks to ~~implement such changes in~~establish uniform rates, charges and terms and conditions of service for the cities and environs of the Texas ~~coast~~Coast service territory. The ~~Railroad Commission approved~~effect of the ~~filing on April 24, 2007. The new~~requested rate changes will be to increase the Texas Coast service ~~charges are expected to be implemented in the second quarter of 2007.~~territory’s revenues by approximately $7 million per year.

Minnesota.~~At September 30,~~ In November 2006, the Minnesota Public Utilities Commission (MPUC) denied a request filed by Gas Operations ~~had recorded~~for a waiver of MPUC rules in order to allow Gas Operations to recover approximately ~~$45~~$21 million ~~as a regulatory asset related to prior years’~~in unrecovered purchased gas costs ~~in its Minnesota service territory. Of the total, approximately $24 million related to the period from July 1, 2004 through June 30, 2006, and approximately~~

In December 2006, the APSC adopted new rules governing affiliate transactions involving public utilities operating in Arkansas. In February 2007, in response to requests by CERC and other gas and electric utilities operating in Arkansas, the APSC granted reconsideration of the rules and stayed their operation in order to permit additional consideration. The parties are awaiting the decision of the APSC following that reconsideration. As originally adopted, the rules could have adverse impacts on CERC’s ability to operate and provide cost-effective utility service in Arkansas. Among other things, the rules would treat as affiliate transactions all transactions between CERC’s Arkansas utility operations and other divisions of CERC, as well as transactions between the Arkansas utility operations and affiliates of CERC. All such affiliate transactions would have to be priced under an asymmetrical pricing formula under which the Arkansas utility operations would benefit from any difference between the cost of providing goods and services to or from the Arkansas utility operations and the market value of those goods or services. Additionally, the Arkansas utility operations would not be permitted to participate in any financing other than to finance retail utility operations in Arkansas, which would preclude continuation of existing financing arrangements in which CERC finances its divisions and subsidiaries, including its Arkansas utility operations.

(a) Non-Trading Activities

Cash Flow Hedges.The Company ~~enters~~has entered into certain derivative instruments that qualify as cash flow hedges under SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” (SFAS No. 133). The objective of these derivative instruments is to hedge the price risk associated with natural gas purchases and sales to reduce cash flow variability related to meeting ~~its~~the Company’s wholesale and retail customer obligations. During each of the three months ended March 31, ~~2006~~2007 and ~~2007,~~2008, hedge ineffectiveness resulted in ~~a gain of $1 million and~~ a loss of less than $1 million ~~respectively,~~ from derivatives that qualify for and are designated as cash flow hedges. No component of the derivative instruments’ gain or loss was excluded from the assessment of effectiveness. If it becomes probable that an anticipated transaction being hedged will not occur, the Company realizes in net income the deferred gains and losses previously recognized in accumulated other comprehensive loss. When an anticipated transaction being hedged affects earnings, the accumulated deferred gain or loss recognized in accumulated other comprehensive loss is reclassified and included in the ~~Condensed~~ Statements of Consolidated Income under the “Expenses” caption “Natural gas.” Cash flows resulting from these transactions in non-trading energy derivatives are included in the ~~Condensed~~ Statements of Consolidated Cash Flows in the same category as the item being hedged. As of March 31, ~~2007,~~2008, the Company expects $2 million ($1 million after-tax) in accumulated other comprehensive income to be reclassified as ~~an increase~~a decrease in ~~natural~~Natural gas expense during the next twelve months.

The length of time the Company is hedging its exposure to the variability in future cash flows using ~~financial~~derivative instruments that have been designated and have qualified as cash flow hedging instruments is ~~primarily two years, with a limited amount up to four years.~~less than one year. The Company’s policy is not to exceed ten years in hedging its exposure.

Hedging of Future Debt Issuances.As of March 31, 2008, the Company had outstanding treasury rate lock derivative instruments (treasury rate locks) with an aggregate notional amount of $300 million, expiration dates of June 2008 and a weighted-average locked U.S. treasury rate on ten-year debt of 4.05%. These treasury rate locks were executed to hedge the ten-year U.S. treasury rate expected to be used in pricing the forecasted issuance of $300 million of fixed-rate debt in 2008, as changes in the U.S treasury rate would cause variability in the Company’s forecasted interest payments. These treasury rate locks qualify as cash flow hedges under SFAS No. 133. Accordingly, unrealized gains and losses associated with the treasury rate locks are recorded as a component of accumulated other comprehensive loss. The realized gain or loss recognized upon settlement of the treasury rate locks will be initially recorded as a component of accumulated other comprehensive loss and will be recognized as a component of interest expense over the life of the related financing arrangement. During the three months ended March 31, 2008, the Company recognized a $14 million loss ($9 million after-tax) for these treasury rate locks in other comprehensive loss. Ineffectiveness for the treasury rate locks was not material during the three months ended March 31, 2008.

Other Derivative Instruments.The Company enters into certain derivative instruments to manage physical commodity price risks that do not qualify or are not designated as cash flow or fair value hedges under SFAS No. 133. The Company utilizes these financial instruments to manage physical commodity price risks and does not engage in proprietary or speculative commodity trading. During the three months ended March 31, ~~2006~~2007 and ~~2007,~~2008, the Company recognized unrealized net ~~gains of $5 million and net~~ losses of $8 million and $22 million, respectively. ~~These derivative gains and~~During the three months ended March 31, 2007, the unrealized net losses are included in the ~~Condensed~~ Statements of Consolidated Income under the “Expenses” caption “Natural ~~gas.~~Gas.”

~~Interest Rate Swaps.~~During 2002, the Company settled forward-starting interest rate swaps having an aggregate notional amount of $1.5 billion at a cost of $156 million, which was recorded in other comprehensive loss and is being amortized into interest expense over the five-year life of the designated fixed-rate debt. Amortization of amounts deferred in accumulated other comprehensive loss for both the three months ended March 31, ~~2006~~2008, unrealized net losses of $20 million are included in the Statements of Consolidated Income under the “Revenues” caption and unrealized net losses of $2 million are included in the Statements of Consolidated Income under the “Expenses” caption “Natural Gas.”

Weather Derivatives.The Company has weather normalization or other rate mechanisms that mitigate the impact of weather in certain of its Gas Operations jurisdictions. The remaining Gas Operations jurisdictions,

Minnesota, Mississippi and Texas, do not have such mechanisms. As a result, fluctuations from normal weather may have a significant positive or negative effect on the results of these operations.

In 2007, ~~was $8~~the Company entered into heating-degree day swaps to mitigate the effect of fluctuations from normal weather on its financial position and cash flows for the 2007/2008 winter heating season. The swaps are based on ten-year normal weather and provide for a maximum payment by either party of $18 million. ~~Hedge ineffectiveness was not material during each of~~During the three months ended March 31, ~~2006 and 2007. As of March 31, 2007,~~2008, the Company ~~expects $12~~recognized an $11 million loss ($87 million after-tax) related to these swaps. This was offset in ~~accumulated other comprehensive loss~~part by increased revenues due to ~~be amortized into interest expense during the next twelve months.~~colder than normal weather.

Embedded Derivative.The Company’s 3.75% convertible senior notes contain contingent interest provisions. The contingent interest component is an embedded derivative as defined by SFAS No. 133, and accordingly, must be split from the host instrument and recorded at fair value on the balance sheet. The value of the contingent interest ~~components~~component was not material at issuance or at March 31, ~~2007.~~2008.

(6) Goodwill

Goodwill by reportable business segment as of both December 31, ~~2006~~2007 and March 31, ~~2007~~2008 is as follows (in millions):


Natural Gas Distribution	$	746	$	746
Interstate Pipelines		579		579
Competitive Natural Gas Sales and Services		339		335
Field Services		25		25
Other Operations		20		11

Total	$	1,709	$	1,696

stock were issued and ~~320,537,680~~328,265,076 shares of CenterPoint Energy common stock were outstanding. See Note 9(b) describing the conversion of the ~~2.875%~~3.75% Convertible Senior Notes in ~~January 2007.~~the first quarter of 2008. Outstanding common shares exclude 166 treasury shares at both December 31, ~~2006~~2007 and March 31, ~~2007.~~2008.

(9) Short-term Borrowings and Long-term Debt

(a) Short-term Borrowings

In ~~2006,~~October 2007, CERC amended its receivables facility and extended the termination date to October ~~30, 2007.~~28, 2008. The facility size ~~is $375 million until May 2007 and~~ will range from $150 million to ~~$325~~$375 million during the period from ~~May~~September 30, 2007 to the October ~~30, 2007~~28, 2008 termination date. ~~Under the terms~~The variable size of the ~~amended receivables~~ facility was designed to track the provisions for sale accounting under SFAS No. 140, “Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities,” were no longer met. Accordingly, advances received by CERC upon the saleseasonal pattern of receivables ~~are accounted for as short-term borrowings as of December 31, 2006 and~~in CERC’s natural gas businesses. At March 31, ~~2007.~~2008, the facility size was $375 million. As of December 31, ~~2006~~2007 and March 31, ~~2007, $187~~2008, $232 million and ~~$337~~$200 million, respectively, was advanced for the purchase of receivables under CERC’s receivables facility.

(b) Long-term Debt

~~Senior Notes.~~In February 2007, the Company issued $250 million aggregate principal amount of senior notes due in February 2017 with an interest rate of 5.95%. The proceeds from the sale of the senior notes were used to repay debt incurred in satisfying the Company’s $255 million cash payment obligation in connection with the conversion and redemption of its 2.875% Convertible Notes.

In February 2007, CERC Corp. issued $150 million aggregate principal amount of senior notes due in February 2037 with an interest rate of 6.25%. The proceeds from the sale of the senior notes were used to repay advances for the purchase of receivables under CERC Corp.’s $375 million receivables facility. Such repayment provides increased liquidity and capital resources for CERC’s general corporate purposes.

Revolving Credit Facilities.As of March 31, ~~2007,~~2008, the Company had no borrowings, ~~and~~ approximately $28 million of outstanding letters of credit and no commercial paper outstanding under its $1.2 billion credit ~~facility,~~facility. As of March 31, 2008, CenterPoint Houston had no borrowings and approximately $4 million of outstanding letters of credit under its $300 million credit facility and CERC Corp. had no$100 million of borrowings and ~~approximately $19~~$35 million of commercial paper outstanding ~~letters of credit~~ under its ~~$550~~$950 million credit facility. ~~Additionally, the~~The Company, CenterPoint Houston and CERC Corp. were in compliance with all debt covenants as of March 31, ~~2007.~~2008.

Transition Bonds. Pursuant to a financing order issued by the Texas Utility Commission in September 2007, in February 2008 a subsidiary of CenterPoint Houston issued approximately $488 million in transition bonds in two tranches with interest rates of 4.192% and 5.234% and final maturity dates of February 2020 and February 2023, respectively. Scheduled final payment dates are February 2017 and February 2020. Through issuance of the transition bonds, CenterPoint Houston securitized transition property of approximately $483 million representing the remaining balance of the CTC adjusted to refund certain unspent environmental retrofit costs and to recover the amount of the fuel reconciliation settlement. See Note 4(a) for further discussion.

Convertible Debt.On May 19, 2003, the Company issued $575 million aggregate principal amount of convertible senior notes due May 15, 2023 with an interest rate of 3.75%. As of March 31, ~~2007,~~2008, holders could convert each of their notes into shares of CenterPoint Energy common stock at a conversion rate of ~~88.3833~~89.4381 shares of common stock per $1,000 principal amount of notes at any time prior to maturity under the following circumstances: (1) if the last reported sale price of CenterPoint Energy common stock for at least 20 trading days during the period of 30 consecutive trading days ending on the last trading day of the previous calendar quarter is greater than or equal to 120% or, following May 15, 2008, 110% of the conversion price per share of CenterPoint Energy common stock on such last trading day, (2) if the notes have been called for redemption, (3) during any period in which the credit ratings assigned to the notes by both Moody’s Investors Service, Inc. (Moody’s) and Standard & Poor’s Ratings Services (S&P), a division of The McGraw-Hill Companies, are lower than Ba2 and BB, respectively, or the notes are no longer rated by at least one of these ratings services or their successors, or (4) upon the occurrence of specified corporate transactions, including the distribution to all holders of CenterPoint Energy common stock of certain rights entitling them to purchase shares of CenterPoint Energy common stock at less than the last reported sale price of a share of CenterPoint Energy common stock on the trading day prior to the declaration date of the distribution or the distribution to all holders of CenterPoint Energy common stock of the Company’s assets, debt securities or certain rights to purchase the Company’s securities, which distribution has a per share value exceeding 15% of the last reported sale price of a share of CenterPoint Energy common stock on the trading day immediately preceding the declaration date for such distribution. The notes originally had a conversion rate of 86.3558 shares of common stock per $1,000 principal amount of notes. However, the conversion rate ~~has~~ increased to ~~88.3833,~~89.4381 shares at March 31, 2008, in accordance with the terms of the notes, ~~due to~~because quarterly common stock dividends declared were in excess of $0.10 per share.

Holders have the right to require the Company to purchase all or any portion of the notes for cash on May 15, 2008, May 15, 2013 and May 15, 2018 for a purchase price equal to 100% of the principal amount of the notes. The convertible senior notes also have a contingent interest feature requiring contingent interest to be paid to holders of

notes commencing on or after May 15, 2008, in the event that the average trading price of a note for the applicable five-trading-day period equals or exceeds 120% of the principal amount of the note as of the day immediately preceding the first day of the applicable six-month interest period. For any six-month period, contingent interest will be equal to 0.25% of the average trading price of the note for the applicable five-trading-day period.

In August 2005, the Company accepted for exchange approximately $572 million aggregate principal amount of its 3.75% convertible senior notes due 2023 (Old Notes) for an equal amount of its new 3.75% convertible senior notes due 2023 (New Notes). As of March 31, 2008, New Notes of approximately $401 million remained outstanding and Old Notes of approximately $3$1 million ~~remain~~remained outstanding. Under the terms of the New Notes, which are substantially similar to the Old Notes, settlement of the principal portion will be made in cash rather than stock.

During the three months ended March 31, 2008, the Company issued 4.4 million shares of its common stock and paid cash of approximately $131 million to settle conversions of approximately $133 million principal amount of its 3.75% convertible senior notes. In April 2008, the Company issued 0.25 million shares of its common stock and paid cash of approximately $11 million to settle a conversion of approximately $11 million principal amount of its convertible notes.

As of December 31, ~~2006~~2007 and March 31, ~~2007,~~2008, the 3.75% convertible senior notes are included as current portion of long-term debt in the Consolidated Balance Sheets because the last reported sale price of CenterPoint Energy common stock for at least 20 trading days during the period of 30 consecutive trading days ending on the last trading day of the quarter was greater than or equal to 120% of the conversion price of the 3.75% convertible senior notes and therefore, the 3.75% convertible senior notes meet the criteria that make them eligible for conversion at the option of the holders of these notes.

In ~~December 2006,~~April 2008, the Company ~~called its 2.875% Convertible Senior Notes due 2024 (2.875% Convertible Notes)~~announced a call for redemption ~~on January 22, 2007~~of its 3.75% convertible senior notes, at 100% of their principal ~~amount. The 2.875% Convertible Notes became immediately convertible at~~amount, on May 30, 2008. Substantially all of such notes are expected to be converted by holders prior to the ~~option~~redemption date, and substantially all of such conversions are expected to be settled with a cash payment for the principal amount and delivery of shares of the ~~holders upon the call~~Company’s common stock for ~~redemption and were convertible through the close of business on the redemption date. Substantially all the $255 million aggregate principal amount~~

~~of the 2.875% Convertible Notes were converted in January 2007. The $255 million principal amount of the 2.875% Convertible Notes was settled in cash and~~ the excess value due converting ~~holders~~holders. If the Company’s closing stock price of ~~$97 million was settled by delivering approximately 5.6 million shares~~$15.57 at April 25, 2008 were unchanged at the dates of the ~~Company’s common stock.~~

~~Junior Subordinated Debentures (Trust Preferred Securities).~~~~In February 2007,~~conversions, assuming the ~~Company’s 8.257% Junior Subordinated Deferrable Interest Debentures having an~~conversion of approximately $391 million aggregate principal amount of ~~$103~~the notes at the current conversion rate, common stock reflecting a conversion premium of $153 million ~~were redeemed~~would be issued to the converting holders. The conversion rate will be increased as a result of the Company’s April 24, 2008 declaration of a regular quarterly cash dividend of $0.1825 per share. Under the terms of the indenture governing the notes, the increased conversion rate will be determined on May 13, 2008.

Purchase of Pollution Control Bonds.In April 2008, the Company purchased $175 million principal amount of pollution control bonds issued on its behalf at ~~104.1285%~~102% of their principal amount. Prior to the purchase, $100 million principal amount of such bonds had a fixed rate of interest of 7.75% and $75 million principal amount of such bonds had a fixed rate of interest of 8%. Depending on market conditions, the ~~related 8.257% capital securities issued by HL&P Capital Trust II were redeemed~~Company expects to remarket both series of bonds, at ~~104.1285%~~100% of their ~~aggregate liquidation value of $100 million.~~principal amounts, in 2008.

(10) Commitments and Contingencies

(a) Natural Gas Supply Commitments

Natural gas supply commitments include natural gas contracts related to the Company’s Natural Gas Distribution and Competitive Natural Gas Sales and Services business segments, which have various quantity requirements and durations, that are not classified as non-trading derivative assets and liabilities in the Company’s Consolidated Balance Sheets as of December 31, ~~2006~~2007 and March 31, ~~2007~~2008 as these contracts meet the SFAS No. 133 exception to be classified as “normal purchases contracts” or do not meet the definition of a derivative. Natural gas supply commitments also include natural gas transportation contracts which do not meet the definition of a derivative. As of March 31, ~~2007,~~2008, minimum payment obligations for natural gas supply commitments are approximately ~~$698~~$532 million for the remaining nine months in ~~2007, $449 million in~~ 2008, ~~$249~~$316 million in 2009, ~~$246~~$296 million in 2010, ~~$244~~$279 million in 2011, ~~and $1.3 billion~~$272 million in 2012 and ~~thereafter.~~$1.2 billion after 2012.

(b) Legal, Environmental and Other Regulatory Matters

Legal Matters

RRI Indemnified Litigation

The Company, CenterPoint Houston or their predecessor, Reliant Energy, Incorporated (Reliant Energy), and certain of their former subsidiaries are named as defendants in several lawsuits described below. Under a master separation agreement between the Company and Reliant Energy, Inc. (formerly Reliant Resources, Inc.) (RRI), the Company and its subsidiaries are entitled to be indemnified by RRI for any losses, including attorneys’ fees and other costs, arising out of the lawsuits described below under~~“Electricity~~ “Electricity and Gas Market Manipulation ~~Cases~~Cases” and ~~Other~~“Other Class Action Lawsuits.”Pursuant to the indemnification obligation, RRI is defending the Company and its subsidiaries to the extent named in these lawsuits. ~~The~~Although the ultimate outcome of these matters cannot be predicted at this ~~time.~~time, the Company has not considered it necessary to establish reserves related to this litigation.

Electricity and Gas Market Manipulation Cases.A large number of lawsuits have been filed against numerous market participants and remain pending in federal court in ~~Wisconsin and~~ Nevada and in state court in California, Missouri and Nevada in connection with the operation of the electricity and natural gas markets in California and certain other states in 2000-2001, a time of power shortages and significant increases in prices. These lawsuits, many of which have been filed as class actions, are based on a number of legal theories, including violation of state and federal antitrust laws, laws against unfair and unlawful business practices, the federal Racketeer Influenced Corrupt Organization Act, false claims statutes and similar theories and breaches of contracts to supply power to governmental entities. Plaintiffs in these lawsuits, which include state officials and governmental entities as well as private litigants, are seeking a variety of forms of relief, including recovery of compensatory damages (in some cases in excess of $1 billion), a trebling of compensatory damages and punitive damages, injunctive relief, restitution, interest due, disgorgement, civil penalties and fines, costs of suit and attorneys’ fees. The Company’s former subsidiary, RRI, was a participant in the California markets, owning generating plants in the state and participating in both electricity and natural gas trading in that state and in western power markets generally.

The Company and/or Reliant Energy have been named in approximately 35 of these lawsuits, which were instituted between 2001 and 2007 and are pending in ~~California state court in San Diego County, in~~ Nevada state court in Clark County, in Missouri state court in ~~Buchanan~~Jackson County and in federal district court in ~~Wisconsin and Nevada and before the Ninth Circuit Court of Appeals.~~Nevada. However, the Company, CenterPoint Houston and Reliant Energy were not participants in the electricity or natural gas markets in California. The Company and Reliant Energy have been dismissed from certain of the lawsuits, either voluntarily by the plaintiffs or by order of the court, and the Company believes it is not a proper defendant in the remaining cases and will continue to seek dismissal from such remaining cases.

To date, several of the electricity complaints have been dismissed, and several of the dismissals have been affirmed by appellate courts. Others have been resolved by the settlement described in the following paragraph. ~~Six~~Three of the gas complaints ~~have also been~~were dismissed based on defendants’ claims of ~~federal preemption and~~ the filed rate doctrine, but the Ninth Circuit Court of Appeals reversed those dismissals and ~~these dismissals either have been appealed or are expected~~remanded the cases back to ~~be appealed.~~the district court for further proceedings. In June 2005, a San Diego state court refused to dismiss other gas complaints on the same basis. In October 2006, RRI reached a tentative settlement of ~~the 12~~11 class action natural gas cases pending in state court in California. ~~This~~The court approved this settlement ~~remains subject~~in June 2007. In the remaining gas cases in state court in California, the Court of Appeals found that the Company was not a successor to ~~final~~the liabilities of a subsidiary of RRI and ordered the state court ~~approval.~~to dismiss the Company. The Company was dismissed in April 2008. The other gas cases remain in the early procedural stages.

In August 2005, RRI reached a settlement with the Federal Energy Regulatory Commission (FERC) enforcement staff, the states of California, Washington and Oregon, California’s three largest investor-owned utilities, classes of consumers from California and other western states, and a number of California city and county government entities that resolves their claims against RRI related to the operation of the electricity markets in California and certain other western states in 2000-2001. The settlement also resolves the claims of the three states and the investor-owned utilities related to the 2000-2001 natural gas markets. The settlement has been approved by the FERC, by the California Public Utilities Commission and by the courts in which the electricity class action cases are pending. Two parties have appealed the courts’ approval of the settlement to the California Court of Appeals. A

party in the FERC proceedings filed a motion for rehearing of the FERC’s order approving the settlement, which the FERC denied onin May ~~30,~~ 2006. That party has filed for review of the FERC’s orders in the Ninth Circuit Court of Appeals. The Company is not a party to the settlement, but may rely on the settlement as a defense to any claims brought against it related to the time when the Company was an affiliate of RRI. The terms of the settlement do not require payment by the Company.

Other Class Action Lawsuits.In May 2002, three class action lawsuits were filed in federal district court in Houston on behalf of participants in various employee benefits plans sponsored by the Company. Two of the lawsuits were dismissed without prejudice. In the remaining lawsuit, the Company and certain ~~current and~~ former members of its benefits committee are defendants. That lawsuit alleged that the defendants breached their fiduciary duties to various employee benefits plans, directly or indirectly sponsored by the Company, in violation of the Employee Retirement Income Security Act of 1974 by permitting the plans to purchase or hold securities issued by the Company when it was imprudent to do so, including after the prices for such securities became artificially inflated because of alleged securities fraud engaged in by the defendants. The complaint sought monetary damages for losses suffered on behalf of the plans and a putative class of plan participants whose accounts held CenterPoint Energy or RRI securities, as well as restitution. In January 2006, the federal district judge granted a motion for summary judgment filed by the Company and the individual defendants. The plaintiffs appealed the ruling to the Fifth Circuit Court of ~~Appeals.~~Appeals (Fifth Circuit), which in April 2008 affirmed the district court’s ruling. The plaintiffs could seek rehearing of that decision by Fifth Circuit and, if that is unsuccessful, further review by the United States Supreme Court. The Company believes that this lawsuit is without merit and will continue to vigorously defend the case. However, the ultimate outcome of this matter cannot be predicted at this time.

Other Legal Matters

Natural Gas Measurement Lawsuits.CERC Corp. and certain of its subsidiaries are defendants in a lawsuit filed in 1997 under the Federal False Claims Act alleging mismeasurement of natural gas produced from federal and Indian lands. The suit seeks undisclosed damages, along with statutory penalties, interest, costs and fees. The complaint is part of a larger series of complaints filed against 77 natural gas pipelines and their subsidiaries and affiliates. An earlier single action making substantially similar allegations against the pipelines was dismissed by the federal district court for the District of Columbia on grounds of improper joinder and lack of jurisdiction. As a result, the various individual complaints were filed in numerous courts throughout the country. This case has been consolidated, together with the other similar False Claims Act cases, in the federal district court in Cheyenne, Wyoming. OnIn October ~~20,~~ 2006, the judge considering this matter granted the defendants’ motion to dismiss the suit on the ground that the court lacked subject matter jurisdiction over the claims ~~asserted, but the~~asserted. The plaintiff has sought review of that dismissal from the Tenth Circuit Court of Appeals, ~~for~~where the ~~10th Circuit.~~matter remains pending.

In addition, CERC Corp. and certain of its subsidiaries are defendants in two mismeasurement lawsuits brought against approximately 245 pipeline companies and their affiliates pending in state court in Stevens County, Kansas. In one case (originally filed in May 1999 and amended four times), the plaintiffs purport to represent a class of royalty owners who allege that the defendants have engaged in systematic mismeasurement of the volume of natural gas for more than 25 years. The plaintiffs amended their petition in this suit in July 2003 in response to an order from the judge denying certification of the plaintiffs’ alleged class. In the amendment the plaintiffs dismissed their

claims against certain defendants (including two CERC Corp. subsidiaries), limited the scope of the class of plaintiffs they purport to represent and eliminated previously asserted claims based on mismeasurement of the British thermal unit (Btu) content of the gas. The same plaintiffs then filed a second lawsuit, again as representatives of a putative class of royalty owners, in which they assert their claims that the defendants have engaged in systematic mismeasurement of the Btu content of natural gas for more than 25 years. In both lawsuits, the plaintiffs seek compensatory damages, along with statutory penalties, treble damages, interest, costs and fees. CERC believes that there has been no systematic mismeasurement of gas and that the lawsuits are without merit. CERC does not expect the ultimate outcome of the lawsuits to have a material impact on the financial condition, results of operations or cash flows of either the Company or CERC.

Gas Cost Recovery Litigation.In October 2002, a ~~suit~~lawsuit was filed on behalf of certain CERC ratepayers in state district court in Wharton County, Texas against the Company, CERC, Entex Gas Marketing Company (EGMC), and certain non-affiliated companies alleging fraud, violations of the Texas Deceptive Trade Practices Act, violations of the Texas Utilities Code, civil conspiracy and violations of the Texas Free Enterprise and Antitrust Act with respect to rates charged to certain consumers of natural gas in the State of Texas. ~~Subsequently, the~~The plaintiffs initially sought certification of a class of Texas ratepayers, but subsequently dropped their request for class certification. The

plaintiffs later added as defendants CenterPoint Energy Marketing Inc., ~~CEGT, United Gas, Inc., Louisiana Unit Gas Transmission Company,~~ CenterPoint Energy Pipeline Services, Inc. (CEPS), and certain other subsidiaries of CERC, and other non-affiliated companies. In February 2005, the case was removed to federal district court in Houston, Texas, and in March 2005, the plaintiffs voluntarily dismissed the case and agreed not to refile the claims asserted unless the Miller County case described below is not certified as a class action or is later decertified.

In October 2004, a lawsuit was filed by certain CERC ratepayers in Texas and Arkansas in circuit court in Miller County, Arkansas against the Company, CERC, EGMC, CenterPoint Energy ~~Trading~~Gas Transmission Company (CEGT), CenterPoint Energy Field Services (CEFS), CEPS, Mississippi River Transmission Corp. (MRT) and ~~Transportation Group, Inc., all of which are subsidiaries of the Company. The plaintiffs alleged that defendants inflated the prices~~other non-affiliated companies alleging fraud, unjust enrichment and civil conspiracy with respect to rates charged to certain consumers of natural ~~gas.~~gas in Arkansas, Louisiana, Minnesota, Mississippi, Oklahoma and Texas. Subsequently, the plaintiffs dropped CEGT and MRT as defendants. Although the plaintiffs in the Miller County case sought class certification, no class was certified. In June 2007, the Arkansas Supreme Court determined that the Arkansas claims were within the sole and exclusive jurisdiction of the Arkansas Public Service Commission (APSC). In response to that ruling, in August 2007 the Miller County court stayed but refused to dismiss the Arkansas claims. In February 2008, the Arkansas Supreme Court directed the Miller County court to dismiss the entire case for lack of jurisdiction. The Miller County court subsequently dismissed the case in accordance with the Arkansas Supreme Court’s mandate and all appellate deadlines have expired.

In June 2007, the Company, CERC, EGMC and other defendants in the Miller County case filed a petition in a district court in Travis County, Texas seeking a determination that the Railroad Commission has original exclusive jurisdiction over the Texas claims asserted in the Miller County case. In October 2007, CEFS and CEPS were joined as plaintiffs to the Travis County case.

In August 2007, the Arkansas plaintiff in the Miller County litigation initiated a complaint at the APSC seeking a decision concerning the extent of the APSC’s jurisdiction over the Miller County case and an investigation into the merits of the allegations asserted in his complaint with respect to CERC. That complaint remains pending at the APSC.

In February 2003, a ~~similar~~ lawsuit was filed in state court in Caddo Parish, Louisiana against CERC with respect to rates charged to a purported class of certain consumers of natural gas and gas service in the State of Louisiana. In February 2004, another suit was filed in state court in Calcasieu Parish, Louisiana against CERC seeking to recover alleged overcharges for gas or gas services allegedly provided by CERC to a purported class of certain consumers of natural gas and gas service without advance approval by the Louisiana Public Service Commission (LPSC). In October 2004, a similar case was filed in district court in Miller County, Arkansas against the Company, CERC, Entex Gas Marketing Company, CEGT, CenterPoint Energy Field Services, CenterPoint Energy Pipeline Services, Inc., Mississippi River Transmission Corp. (MRT) and other non-affiliated companies alleging fraud, unjust enrichment and civil conspiracy with respect to rates charged to certain consumers of natural gas in at least the states of Arkansas, Louisiana, Mississippi, Oklahoma and Texas. Subsequently, the plaintiffs dropped as defendants CEGT and MRT. At the time of the filing of each of the Caddo and Calcasieu Parish cases, the plaintiffs in those cases filed petitions with the LPSC relating to the same alleged rate overcharges. The Caddo and Calcasieu Parish ~~cases~~lawsuits have been stayed pending the resolution of the ~~respective proceedings~~petitions filed with the LPSC. In August 2007, the LPSC issued an order approving a Stipulated Settlement in the review initiated by the ~~LPSC. The~~ plaintiffs in the ~~Miller County case seek class certification,~~Calcasieu Parish litigation. In the LPSC proceeding, CERC’s gas purchases were reviewed back to 1971. The review concluded that CERC’s gas costs were “reasonable and prudent,” but CERC agreed to credit to jurisdictional customers approximately $920,000, including interest, related to certain off-system sales. A regulatory liability was established and the ~~proposed class has not been certified. In February 2005,~~Company began refunding that amount to jurisdictional customers in September 2007. A similar review by the ~~Wharton County case~~LPSC related to the Caddo Parish litigation was removed to federal district court in Houston, Texas, and in March 2005, the plaintiffs voluntarily moved to dismiss the case and agreed not to refile the claims asserted unless the Miller County case is not certified as a class action or is later decertified.resolved without additional payment by CERC.

The range of relief sought by the plaintiffs in these cases includes injunctive and declaratory relief, restitution for the alleged overcharges, ~~disgorgement of illegal profits,~~ exemplary damages or trebling of actual damages, civil penalties and attorney’s fees. ~~In these cases, the~~The Company, CERC and their affiliates deny that they have overcharged any of their customers for natural gas and believe that the amounts recovered for purchased gas have been shown in the reviews described above to be in accordance with what is permitted by state and municipal regulatory authorities. The Company and CERC do not expect the outcome of these matters to have a material impact on the financial condition, results of operations or cash flows of either the Company or CERC.

Storage Facility Litigation.In February 2007, an Oklahoma district court in Coal County, Oklahoma, granted a summary judgment against CEGT in a case, Deka Exploration, Inc. v. CenterPoint Energy, filed by holders of oil and gas leaseholds and some mineral interest owners in lands underlying CEGT’s Chiles Dome Storage Facility. The dispute concerns “native gas” that may have been in the Wapanucka formation underlying the Chiles Dome facility when that facility was constructed in 1979 by a CERC entity that was the predecessor in interest of CEGT.

Environmental Matters

~~Hydrocarbon Contamination.~~CERC Corp. and certain of its subsidiaries are among the defendants in lawsuits filed beginning in August 2001 in Caddo Parish and Bossier Parish, Louisiana. The suits allege that, at some unspecified date prior to 1985, the defendants allowed or caused hydrocarbon or chemical contamination of the Wilcox Aquifer, which lies beneath property owned or leased by certain of the defendants and which is the sole or primary drinking water aquifer in the area. The primary source of the contamination is alleged by the plaintiffs to be a gas processing facility in Haughton, Bossier Parish, Louisiana known as the “Sligo Facility,” which was formerly operated by a predecessor in interest of CERC Corp. This facility was purportedly used for gathering natural gas from surrounding wells, separating liquid hydrocarbons from the natural gas for marketing, and transmission of natural gas for distribution.

Beginning about 1985, the predecessors of certain CERC Corp. defendants engaged in a voluntary remediation of any subsurface contamination of the groundwater below the property they owned or leased. This work has been done in conjunction with and under the direction of the Louisiana Department of Environmental Quality. The plaintiffs seek monetary damages for alleged damage to the aquifer underlying their property, including the cost of restoring their property to its original condition and damages for diminution of value of their property. In addition, plaintiffs seek damages for trespass, punitive, and exemplary damages. The parties have reached an agreement on terms of a settlement in principle of this matter. That settlement would require approval from the Louisiana Department of Environmental Quality of an acceptable remediation plan that could be implemented by CERC. CERC currently is seeking that approval. If the currently agreed terms for settlement are ultimately implemented, the Company and CERC do not expect the ultimate cost associated with resolving this matter to have a material impact on the financial condition, results of operations or cash flows of either the Company or CERC.

Manufactured Gas Plant Sites.CERC and its predecessors operated manufactured gas plants (MGP) in the past. In Minnesota, CERC has completed remediation on two sites, other than ongoing monitoring and water treatment. There are five remaining sites in CERC’s Minnesota service territory. CERC believes that it has no liability with respect to two of these sites.

At March 31, ~~2007,~~2008, CERC had accrued $14 million for remediation of these Minnesota sites and the estimated range of possible remediation costs for these sites was $4 million to $35 million based on remediation continuing for 30 to 50 years. The cost estimates are based on studies of a site or industry average costs for remediation of sites of similar size. The actual remediation costs will be dependent upon the number of sites to be remediated, the participation of other potentially responsible parties (PRP), if any, and the remediation methods used. CERC has utilized an environmental expense tracker mechanism in its rates in Minnesota to recover estimated costs in excess of insurance recovery. As of March 31, ~~2007,~~2008, CERC had collected $13 million from insurance companies and rate payers to be used for future environmental remediation.

In addition to the Minnesota sites, the United States Environmental Protection Agency and other regulators have investigated MGP sites that were owned or operated by CERC or may have been owned by one of its former affiliates. CERC has been named as a defendant in a lawsuit filed in the United States District Court, District of Maine, under which contribution is sought by private parties for the cost to remediate former MGP sites based on the previous ownership of such sites by former affiliates of CERC or its divisions. CERC has also been identified as a PRP by the State of Maine for a site that is the subject of the lawsuit. In June 2006, the federal district court in Maine ruled that the current owner of the site is responsible for site remediation but that an additional evidentiary hearing is required to determine if other potentially responsible parties, including CERC, would have to contribute to that remediation. The Company is investigating details regarding the site and the range of environmental expenditures for potential remediation. However, CERC believes it is not liable as a former owner or operator of the site under the Comprehensive Environmental, Response, Compensation and Liability Act of 1980, as amended, and applicable state statutes, and is vigorously contesting ~~those suits~~the suit and its designation as a PRP.

Mercury Contamination.The Company’s pipeline and distribution operations have in the past employed elemental mercury in measuring and regulating equipment. It is possible that small amounts of mercury may have been spilled in the course of normal maintenance and replacement operations and that these spills may have contaminated the immediate area with elemental mercury. The Company has found this type of contamination at some sites in the past, and the Company has conducted remediation at these sites. It is possible that other

be asserted in the future. In 2004, the Company sold its generating business, to which most of these claims relate, to Texas Genco LLC, which is now known as NRG Texas LP (NRG). Under the terms of the arrangements regarding separation of the generating business from the Company and its sale to Texas Genco LLC, ultimate financial responsibility for uninsured losses from claims relating to the generating business has been assumed by Texas Genco LLC and its successor, but the Company has agreed to continue to defend such claims to the extent they are covered by insurance maintained by the Company, subject to reimbursement of the costs of such defense from the purchaser. Although their ultimate outcome cannot be predicted at this time, the Company intends to continue vigorously contesting claims that it does not consider to have merit and does not expect, based on its experience to date, these matters, either individually or in the aggregate, to have a material adverse effect on the Company’s financial condition, results of operations or cash flows.

Other Environmental.From time to time the Company has received notices from regulatory authorities or others regarding its status as a PRP in connection with sites found to require remediation due to the presence of environmental contaminants. In addition, the Company has been named from time to time as a defendant in litigation related to such sites. Although the ultimate outcome of such matters cannot be predicted at this time, the Company does not expect, based on its experience to date, these matters, either individually or in the aggregate, to have a material adverse effect on the Company’s financial condition, results of operations or cash flows.

Other Proceedings

The Company is involved in other legal, environmental, tax and regulatory proceedings before various courts, regulatory commissions and governmental agencies regarding matters arising in the ordinary course of business. Some of these proceedings involve substantial amounts. The Company regularly analyzes current information and, as necessary, provides accruals for probable liabilities on the eventual disposition of these matters. The Company does not expect the disposition of these matters to have a material adverse effect on the Company’s financial condition, results of operations or cash flows.

Guaranties

Prior to the Company’s distribution of its ownership in RRI to its shareholders, CERC had guaranteed certain contractual obligations of what became RRI’s trading subsidiary. Under the terms of the separation agreement between the companies, RRI agreed to extinguish all such guaranty obligations prior to separation, but at the time of separation in September 2002, RRI had been unable to extinguish all obligations. To secure ~~the Company and~~ CERC against obligations under the remaining guaranties, RRI agreed to provide cash or letters of credit for ~~the~~CERC’s benefit, ~~of CERC and the Company,~~ and undertook to use commercially reasonable efforts to extinguish the remaining guaranties. In December 2007, the Company, CERC ~~currently holds~~and RRI amended that agreement and CERC released the letters of credit it held as security. Under the revised agreement RRI agreed to provide cash or new letters of credit to secure CERC against exposure under the remaining guaranties as calculated under the new agreement if and to the extent changes in ~~the amount~~market conditions exposed CERC to a risk of ~~$33.3 million issued~~loss on ~~behalf~~those guaranties.

The potential exposure of ~~RRI against guaranties that have not been released. The Company’s current exposure~~CERC under the guaranties relates to ~~CERC’s guaranty of the~~ payment ~~by RRI~~ of demand charges related to transportation ~~contracts with one counterparty. The demand charges are approximately $53 million per year through 2015, $49 million in 2016, $38 million in 2017 and $13 million in 2018.~~contracts. RRI continues to meet its obligations under the ~~transportation~~ contracts, and, on the ~~Company believes~~basis of current market conditions, ~~make those contracts valuable for transportation services in~~ the ~~near term.~~Company and CERC believe that additional security is not needed at this time. However, ~~changes in market conditions could affect the value of those contracts. If~~if RRI should fail to perform its obligations under the ~~transportation~~ contracts or if RRI should fail to provide adequate security in the ~~Company’s~~event market conditions change adversely, the Company would retain exposure to the counterparty under the guaranty could exceed the security provided by RRI. The Company has requested RRI to increase the amount of its existing letters of credit or, in the alternative, to obtain a release of CERC’s obligations under the guaranty. ~~In June 2006, the RRI trading subsidiary and CERC jointly filed a complaint at the FERC against the counterparty on the CERC guaranty.~~

In the complaint, the RRI trading subsidiary seeks a determination by the FERC that the security demanded by the counterparty exceeds the level permitted by the FERC’s policies. The complaint asks the FERC to require the counterparty to release CERC from its guaranty obligation and, in its place, accept (i) a guaranty from RRI of the obligations of the RRI trading subsidiary, and (ii) letters of credit limited to (A) one year of demand charges for a transportation agreement related to a 2003 expansion of the counterparty’s pipeline, and (B) three months of demand charges for three other transportation agreements held by the RRI trading subsidiary. The counterparty has argued that the amount of the guaranty does not violate the FERC’s policies and that the proposed substitution of credit support is not authorized under the counterparty’s financing documents or required by the FERC’s policy. The parties have now completed their submissions to the FERC regarding the complaint. The Company cannot predict what action the FERC may take on the complaint or when the FERC may rule. In addition to the FERC proceeding, in February 2007 the Company and CERC made a formal demand on RRI under procedures provided by the Master Separation Agreement, dated as of December 31, 2000, between Reliant Energy and RRI. That demand seeks to resolve the disagreement with RRI over the amount of security RRI is obligated to provide with respect to this guaranty. In conjunction with discussion of that demand, the Company and RRI entered into an agreement in March 2007 to delay further proceedings regarding this dispute until October 2007 in order to permit further discussions. It is possible that an arbitration proceeding between the companies could be pursued, but when and on what terms the disagreement with RRI will ultimately be resolved cannot be predicted.

(11) Income Taxes

During the three months ended March 31, ~~2006~~2007 and ~~2007,~~2008, the effective tax rate was ~~45%~~36% and ~~36%~~37%, respectively. The most significant item affecting the comparability of the effective tax rate ~~was an increase to~~is the ~~tax reserve~~2008 classification of approximately ~~$14~~$4 million ~~relating to~~of Texas margin tax as an income tax for CenterPoint Houston.

The following table summarizes the ~~Zero Premium Exchangeable Subordinated Notes (ZENS)~~Company’s liability for uncertain tax positions in accordance with FASB Interpretation No. (FIN) 48, “Accounting for Uncertainty in Income Taxes — an Interpretation of FASB Statement No. 109,” at December 31, 2007 and ~~Automatic Common Exchange Securities issues in the first quarter of 2006.~~March 31, 2008 (in millions):


	December 31,		March 31,
	2007		2008
Liability for uncertain tax positions	$	82	$	89
Portion of liability for uncertain tax positions that, if recognized, would reduce the effective income tax rate		10		11
Interest accrued on uncertain tax positions		4		5

(12) Earnings Per Share

The following table reconciles numerators and denominators of the Company’s basic and diluted earnings per share calculations:


	Three Months Ended March 31,				Three Months Ended March 31,
	2006		2007		2007		2008
	(in millions, except share and				(in millions, except share and
	per share amounts)				per share amounts)
Basic earnings per share calculation:
Net income	$	88	$	130	$	130	$	123


Weighted average shares outstanding		310,846,000		318,060,000		318,060,000		327,279,000


Basic earnings per share:
Net income	$	0.28	$	0.41	$	0.41	$	0.38


Diluted earnings per share calculation:
Net income	$	88	$	130	$	130	$	123


Weighted average shares outstanding		310,846,000		318,060,000		318,060,000		327,279,000
Plus: Incremental shares from assumed conversions:
Stock options (1)		1,216,000		1,237,000		1,237,000		869,000
Restricted stock		957,000		1,328,000		1,328,000		1,127,000
2.875% convertible senior notes		150,000		1,179,000		1,179,000		—
3.75% convertible senior notes		5,424,000		18,299,000		18,299,000		10,173,000

Weighted average shares assuming dilution		318,593,000		340,103,000		340,103,000		339,448,000


Diluted earnings per share:
Net income	$	0.28	$	0.38	$	0.38	$	0.36

wholesale or retail customers in differing regulatory environments. The accounting policies of the business segments are the same as those described in the summary of significant accounting policies except that some executive benefit costs have not been allocated to business segments. The Company uses operating income as the measure of profit or loss for its business segments.

The Company’s reportable business segments include the following: Electric Transmission & Distribution, Natural Gas Distribution, Competitive Natural Gas Sales and Services, Interstate Pipelines, Field Services and Other Operations. The electric transmission and distribution function (CenterPoint Houston) is reported in the Electric Transmission & Distribution business segment. Natural Gas Distribution consists of intrastate natural gas sales to, and natural gas transportation and distribution for, residential, commercial, industrial and institutional customers. Competitive Natural Gas Sales and Services represents the Company’s non-rate regulated gas sales and services operations, which consist of three operational functions: wholesale, retail and intrastate pipelines. Beginning in the fourth quarter of 2006, the Company began reporting its interstate pipelines and field services businesses as two separate business segments, the Interstate Pipelines business segment and the Field Services business segment. These business segments were previously aggregated and reported as the Pipelines and Field Services business segment. The Interstate Pipelines business segment includes the interstate natural gas pipeline operations. The Field Services business segment includes the natural gas gathering operations. Other Operations consists primarily of other corporate operations which support all of the Company’s business operations. ~~All prior periods have been recast to conform to the 2007 presentation.~~

Long-lived assets include net property, plant and equipment, net goodwill and other intangibles and equity investments in unconsolidated subsidiaries. Intersegment sales are eliminated in consolidation.

Financial data for business segments and products and services are as follows (in millions):


	For the Three Months Ended March 31, 2006												For the Three Months Ended March 31, 2007
	Revenues from			Net						Total Assets			Revenues from			Net						Total Assets
	External			Intersegment			Operating			as of December 31,			External			Intersegment			Operating			as of December 31,
	Customers			Revenues			Income (Loss)			2006			Customers			Revenues			Income (Loss)			2007
Electric Transmission & Distribution	$	385	⁽¹⁾	$	—		$	110		$	8,463		$	406	⁽¹⁾	$	—		$	104		$	8,358
Natural Gas Distribution		1,477			3			103			4,463			1,564			3			129			4,332
Competitive Natural Gas Sales and Services		1,126			37			25			1,501			1,047			17			56			1,221
Interstate Pipelines		56			33			49			2,738			59			31			44			3,007
Field Services		31			10			24			608			28			11			22			669
Other Operations		2			2			(5	)		2,047	⁽²⁾		2			—			(2	)		1,956	⁽²⁾
Eliminations		—			(85	)		—			(2,187	)		—			(62	)		—			(1,671	)

Consolidated	$	3,077		$	—		$	306		$	17,633		$	3,106		$	—		$	353		$	17,872

Item 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS OF CENTERPOINT ENERGY, INC. AND SUBSIDIARIES

The following discussion and analysis should be read in combination with our Interim Condensed Financial Statements contained in thisForm 10-Q and our Annual Report onForm 10-K for the year ended December 31, 2007 (2007Form 10-K).

EXECUTIVE SUMMARY

Recent Events

Debt Financing Transactions

In ~~December 2006,~~April 2008, we ~~called~~purchased $175 million principal amount of pollution control bonds issued on our ~~2.875%~~behalf at 102% of their principal amount. Prior to the purchase, $100 million principal amount of such bonds had a fixed rate of interest of 7.75% and $75 million principal amount of such bonds had a fixed rate of interest of 8%. Depending on market conditions, we expect to remarket both series of bonds, at 100% of their principal amounts, in 2008.

During the three months ended March 31, 2008, we issued 4.4 million shares of our common stock and paid cash of approximately $131 million to settle conversions of approximately $133 million principal amount of our 3.75% convertible senior notes. Convertible ~~Senior Notes due 2024 (2.875% Convertible Notes)~~senior notes aggregating $402 million remained outstanding at March 31, 2008. In April 2008, we issued 0.25 million shares of our common stock and paid cash of approximately $11 million to settle a conversion of approximately $11 million principal amount of our 3.75% convertible notes.

In April 2008, we announced a call for redemption ~~on January 22, 2007~~of our 3.75% convertible senior notes, at 100% of their principal amount, ~~plus accrued and unpaid interest~~on May 30, 2008. Substantially all of such notes are expected to be converted by holders prior to the redemption ~~date. The 2.875% Convertible Notes became immediately convertible~~date, and substantially all of such conversions are expected to be settled with a cash payment for the principal amount and delivery of shares of our common stock for the excess value due converting holders. If our closing stock price of $15.57 at April 25, 2008 were unchanged at the ~~option~~dates of the ~~holders upon our call for redemption and were convertible through~~conversions, assuming the ~~close~~conversion of ~~business on the redemption date. Substantially all the $255~~approximately $391 million aggregate principal amount of the ~~2.875% Convertible Notes were converted~~notes at the current conversion rate, common stock reflecting a conversion premium of $153 million would be issued to the converting holders. The conversion rate will be increased as a result of our April 24, 2008 declaration of a regular quarterly cash dividend of $0.1825 per share. Under the terms of the indenture governing the notes, the increased conversion rate will be determined on May 13, 2008.

Transition Bonds

Pursuant to a financing order issued by the Public Utility Commission of Texas (Texas Utility Commission) in September 2007, in February 2008 a subsidiary of CenterPoint Energy Houston Electric, LLC (CenterPoint Houston) issued approximately $488 million in transition bonds in two tranches with interest rates of 4.192% and 5.234% and final maturity dates in February 2020 and February 2023, respectively. Scheduled final payment dates are February 2017 and February 2020. Through issuance of the transition bonds, CenterPoint Houston securitized transition property of approximately $483 million representing the remaining ~~amount was redeemed. The $255 million principal~~balance of the competition transition charge (CTC) adjusted to refund certain unspent environmental retrofit costs and to recover the amount of the 2.875% Convertible Notes was settled in cash in the first quarter of 2007 and the excess value due converting holders of $97 million was settled by delivering approximately 5.6 million shares of our common stock.

In February 2007, we redeemed $103 million aggregate principal amount of 8.257% Junior Subordinated Deferrable Interest Debentures at 104.1285% of their aggregate principal amount and the related 8.257% capital securities issued by HL&P Capital Trust II were redeemed at 104.1285% of their $100 million aggregate liquidation value.

In February 2007, we issued $250 million aggregate principal amount of senior notes due in February 2017 with an interest rate of 5.95%. The proceeds from the sale of the senior notes were used to repay debt incurred in satisfying our $255 million cash payment obligation in connection with the conversion and redemption of our 2.875% Convertible Notes as discussed above.

In February 2007, CenterPoint Energy Resources Corp. (CERC Corp., together with its subsidiaries, CERC) issued $150 million aggregate principal amount of senior notes due in February 2037 with an interest rate of 6.25%. The proceeds from the sale of the senior notes were used to repay advances for the purchase of receivables under CERC Corp.’s $375 million receivables facility. Such repayment provides increased liquidity and capital resources for CERC’s general corporate purposes.fuel reconciliation settlement.

Interstate ~~Pipeline Expansion~~Pipelines

~~Carthage to Perryville.~~In ~~April~~ May��2007, CenterPoint Energy Gas Transmission (CEGT), a wholly owned subsidiary of CERC Corp., ~~completed construction~~received Federal Energy Regulatory Commission (FERC) approval for the third phase of its Carthage to Perryville pipeline project, a 172-mile, 42-inch diameter pipeline and related compression facilities for the transportation of gas from Carthage, Texas to CEGT’s Perryville hub in Northeast Louisiana. On May 1, 2007, CEGT began service under its firm transportation agreements with shippers of approximately 960 million cubic feet per day. This completes the first phase of the Carthagenortheast Louisiana, to ~~Perryville project. The second phase of the project remains on schedule for a mid-summer completion and involves adding compression to increase the total~~expand capacity of the pipeline to ~~approximately 1.25 billion cubic feet (Bcf) per day. CEGT has signed firm contracts for the full capacity of the 1.25~~1.5 Bcf per day ~~pipeline.~~by adding additional compression and operating at higher pressures. In July 2007, CEGT received approval from the Pipeline and Hazardous Materials Administration (PHMSA) to increase the maximum allowable operating pressure. The PHMSA’s approval contained certain conditions and requirements. In March 2008, CEGT met these conditions and gave notice to PHMSA that it would be increasing the pressure in 30 days. In April 2008, CEGT raised the maximum allowable pressure and concurrently placed the phase three expansion in-service. CEGT has executed contracts for approximately 150 MMcf per day of the 250 MMcf per day phase three expansion.

2223

In September 2007, CEGT initiated an investigation into allegations received from two former employees of the manufacturer of pipe installed in CEGT’s Carthage to Perryville pipeline segment. That pipeline segment was placed in commercial service in May 2007 after satisfactory completion of hydrostatic testing designed to ensure that the pipe and its welds would be structurally sound when placed in service and operated at design pressure. According to the complainants, records relating to radiographic inspections of certain welds made at the fabrication facility had been altered resulting in the possibility that pipe with alleged substandard welds had been installed in the pipeline. In conducting its investigation, among other things, CEGT and its counsel interviewed the complainants and other individuals, including CEGT and contractor personnel, and reviewed documentation related to the manufacture and construction of the pipeline, including radiographic records related to the allegedly deficient welds. CEGT kept appropriate governmental officials informed throughout its investigation and consulted appropriate technical consultants and pre-existing regulatory guidance. Pursuant to a course of action proposed by CEGT,CEGT excavated and inspected certain welds, and in each case, CEGT found those welds to be structurally sound. CEGT and its counsel have now formally concluded their investigation, finding no credible support for the allegation that pipe with substandard welds may have been installed in the pipeline. CEGT has informed the relevant government agencies of these conclusions, and has informed those agencies that CEGT does not intend to take any additional action or to alter or modify the pipeline’s operations.

Effective April 1, 2008, Mississippi River Transmission Corp. signed a 5-year extension of its firm transportation and storage contracts with Laclede Gas Company (Laclede). In 2007, approximately 10% of Interstate Pipelines operating revenues was attributable to services provided to Laclede.

CONSOLIDATED RESULTS OF OPERATIONS

All dollar amounts in the tables that follow are in millions, except for per share amounts.


	Three Months Ended March 31,						Three Months Ended March 31,
	2006			2007			2007			2008
Revenues	$	3,077		$	3,106		$	3,106		$	3,363
Expenses		2,771			2,753			2,753			3,027

Operating Income		306			353			353			336
Interest and Other Finance Charges		(115	)		(123	)		(123	)		(115	)
Interest on Transition Bonds		(33	)		(31	)		(31	)		(33	)
Other Income, net		2			3			3			9

Income Before Income Taxes		160			202			202			197
Income Tax Expense		(72	)		(72	)		(72	)		(74	)

Net Income	$	88		$	130		$	130		$	123


Basic Earnings Per Share	$	0.28		$	0.41		$	0.41		$	0.38


Diluted Earnings Per Share	$	0.28		$	0.38		$	0.38		$	0.36

Three months ended March 31, ~~2007~~2008 compared to three months ended March 31, ~~2006~~2007

Our Electric Transmission & Distribution business segment reported operating income of ~~$104~~$91 million for the three months ended March 31, ~~2007,~~2008, consisting of ~~$73~~$54 million for the regulated electric transmission and distribution utility (TDU) ~~(including $11~~, $5 million for the ~~competition transition charge (CTC))~~CTC and ~~$31~~$32 million related to the transition bonds. For the three months ended March 31, ~~2006,~~2007, operating income totaled ~~$110~~$104 million, consisting of ~~$78~~$62 million for the TDU, ~~(including $16~~$11 million for the ~~CTC)~~CTC and ~~$32~~$31 million related to the transition bonds. ~~Revenues for~~The reduction in operating income from the TDU ~~increased~~resulted from reduced usage ($11 million), in part due to milder weather, higher ~~usage primarily from favorable weather~~operating expenses ($22 million), customer growth, with nearly 39,000 metered customers added since March 31, 2006 ($4 million), higher transmission revenues ($4 million) and revised charges for discretionary services ($3 million). This was partially offset by the impact of the rate reduction resulting from the 2006 rate settlement that was implemented October 2006 ($11 million) and lower CTC return resulting from the reduction in our allowed rate of return ($5 million). Operation and maintenance expense increased primarily due to a gain on the sale of property in 2006 ($14 million), higher transmission costs ($78 million), and ~~increased low income expenses largely due to the 2006 rate settlement~~higher net transmission costs ($3 million), partially offset by ~~lower corporate support services costs~~higher revenues ($47 million) ~~primarily~~ due to ~~staff reductions~~customer growth from the addition of over 52,000 new customers and higher revenues from ancillary services ($2 million). Taxes other than income taxes were lower by $4 million primarily as a result of the Texas margin tax being classified as an income tax for reporting purposes in ~~2006.~~2008.

Natural Gas Distribution

For information regarding factors that may affect the future results of operations of our Natural Gas Distribution business segment, please read “Risk Factors — Risk Factors Affecting Our Natural Gas Distribution, Competitive Natural Gas Sales and Services, Interstate Pipelines and Field Services Businesses,” “ — Risk Factors Associated with Our Consolidated Financial Condition” and “— Risks Common to Our Business and Other Risks” in Item 1A of Part I of our ~~2006~~2007 Form 10-K.

The following table provides summary data of our Natural Gas Distribution business segment for the three months ended March 31, ~~2006~~2007 and ~~2007~~2008 (in millions, except throughput and customer data):


	Three Months Ended March 31,				Three Months Ended March 31,
	2006		2007		2007		2008
Revenues	$	1,480	$	1,567	$	1,567	$	1,700

Expenses:
Natural gas		1,146		1,212		1,212		1,333
Operation and maintenance		150		147		147		156
Depreciation and amortization		38		38		38		39
Taxes other than income taxes		43		41		41		51

Total expenses		1,377		1,438		1,438		1,579

Operating Income	$	103	$	129	$	129	$	121


Throughput (in Bcf):
Residential		67		86		86		84
Commercial and industrial		72		81		81		83

Total Throughput		139		167		167		167


Average number of customers:
Residential		2,896,766		2,946,203		2,946,203		2,975,591
Commercial and industrial		245,766		245,576		245,576		250,988

Total		3,142,532		3,191,779		3,191,779		3,226,579

Competitive Natural Gas Sales and Services

For information regarding factors that may affect the future results of operations of our Competitive Natural Gas Sales and Services business segment, please read “Risk Factors — Risk Factors Affecting Our Natural Gas Distribution, Competitive Natural Gas Sales and Services, Interstate Pipelines and Field Services Business,” “ — Risk Factors Associated with Our Consolidated Financial Condition” and “— Risks Common to Our Business and Other Risks” in Item 1A of Part I of our ~~2006~~2007 Form 10-K.

The following table provides summary data of our Competitive Natural Gas Sales and Services business segment for the three months ended March 31, ~~2006~~2007 and ~~2007~~2008 (in millions, except throughput and customer data):


	Three Months Ended March 31,				Three Months Ended March 31,
	2006		2007		2007		2008
Revenues	$	1,163	$	1,064	$	1,064	$	1,120

Expenses:
Natural gas		1,129		998		998		1,105
Operation and maintenance		8		9		9		8
Depreciation and amortization		—		—		––		1
Taxes other than income taxes		1		1		1		—

Total expenses		1,138		1,008		1,008		1,114

Operating Income	$	25	$	56	$	56	$	6


Throughput (in Bcf):
Wholesale — third parties		89		94
Wholesale — affiliates		11		3
Wholesale – third parties						94		70
Wholesale – affiliates						3		2
Retail and Pipeline		58		58		58		66

Total Throughput		158		155		155		138


Average number of customers:
Wholesale		145		223		223		154
Retail and Pipeline		6,664		6,764		6,764		8,338

Total		6,809		6,987		6,987		8,492

Our Competitive Natural Gas Sales and Services business segment reported operating income of $6 million for the three months ended March 31, 2008 compared to $56 million for the three months ended March 31, ~~2007 compared to $25 million for the three months ended March 31, 2006.~~2007. The ~~increase~~decrease in operating income of ~~$31~~$50 million was primarily due to ~~increased~~higher operating margins (revenues less natural gas costs) in 2007 related to sales of gas from inventory ~~($28 million) partially offset by an~~that was written down to the lower of cost or market in prior periods of $28 million in the first quarter of 2007 compared to $4 million in the first quarter of 2008 for a net decrease of $24 million. Our Competitive Natural Gas Sales and Services business segment purchases and stores natural gas to meet certain future sales requirements and enters into derivative contracts to hedge the economic value of the future sales. The unfavorable ~~change resulting from~~ mark-to-market accounting for non-trading financial derivatives ~~($14 million). The~~for the first quarter of ~~2006 included~~2008 of $22 million versus $8 million for the same period in 2007 accounted for a ~~$13~~further net $14 million ~~write-down~~decrease. The additional decrease in operating income of ~~natural gas inventory~~$12 million in this quarter compared to the ~~lower of average cost or market. Natural gas that is purchased for inventory is accounted for at the lower of average cost or market price at each balance sheet date.~~same quarter last year was primarily due to a reduction in margin as basis and summer/winter spreads narrowed.

Future Sources and Uses of Cash

Our liquidity and capital requirements are affected primarily by our results of operations, capital expenditures, debt service requirements, tax payments, working capital needs, various regulatory actions and appeals relating to such regulatory actions. Our principal cash requirements for the remaining nine months of ~~2007~~2008 include the following:

	•		approximately ~~$780~~$813 million of capital ~~requirements;~~expenditures;

	•		~~an investment in the Southeast Supply Header (SESH) pipeline project of approximately $150 million;~~

	•		~~potential~~ cash ~~settlements~~settlement obligations in connection with possible conversions by holders of our 3.75% convertible senior notes, having an aggregate principal amount of ~~$575~~$402 million at March 31, 2008 or in connection with the redemption of such notes on May 30, 2008;

	•		maturing long-term debt aggregating approximately $282 million, including $82 million of transition bonds;

	•		the cash purchase of $175 million of pollution control bonds issued on our behalf;

	•		investment in and advances to SESH of approximately $185 million;

	•		dividend payments on CenterPoint Energy common stock and ~~debt service payments; and~~

	•		~~$75 million of maturing transition bonds.~~interest payments on debt.

We expect that borrowings under our credit facilities, the proceeds from the February 2008 issuance of $488 million of transition bonds (discussed below), anticipated cash proceeds from the remarketing of $175 million of pollution control bonds purchased in April 2008 (discussed below) and anticipated cash flows from operations will be sufficient to meet our cash needs ~~for the remaining nine months of 2007.~~in 2008. Cash needs or discretionary financing or refinancing may also result in the issuance of equity or debt securities in the capital markets.

Transition Bonds.In February 2008, a new special purpose subsidiary of CenterPoint Houston issued approximately $488 million in transition bonds pursuant to a financing order issued by the Texas Utility Commission in September 2007. Through issuance of the transition bonds, CenterPoint Houston securitized transition property of approximately $483 million representing the remaining balance of the CTC adjusted to refund certain unspent environmental retrofit costs and to recover the amount of the fuel reconciliation settlement. Proceeds were used by the special purpose entity to purchase $483 million of transition property from CenterPoint Houston and to pay costs of issuance. Following a subsequent distribution to us, we used the proceeds for general corporate purposes, including the repayment of debt and the making of loans to or investments in affiliates.

Purchase of Pollution Control Bonds.In April 2008, we purchased $175 million principal amount of pollution control bonds issued on our behalf at 102% of their principal amount. Prior to the purchase, $100 million principal amount of such bonds had a fixed rate of interest of 7.75% and $75 million principal amount of such bonds had a fixed rate of interest of 8%. Depending on market conditions, we expect to remarket both series of bonds, at 100% of their principal amounts, in 2008.

Convertible Debt.As of December 31, 2007 and March 31, ~~2007,~~2008, the 3.75% convertible senior notes discussed in Note 9(b) to our consolidated financial statements have been included as current portion of long-term debt in our ~~Condensed~~ Consolidated Balance Sheets because the last reported sale price of ~~CenterPoint Energy~~our common stock for at least 20 trading days during the period of 30 consecutive trading days ending on the last trading day of the ~~first~~fourth quarter of 2007 was greater than or equal to 120% of the conversion price of the 3.75% convertible senior notes and therefore, during the ~~second~~

first quarter of ~~2007,~~2008, the 3.75% convertible senior notes meet the criteria that make them eligible for conversion at the option of the holders of these notes. During the three months ended March 31, 2008, we issued 4.4 million shares of our common stock and paid cash of approximately $131 million to settle conversions of approximately $133 million principal amount of our 3.75% convertible senior notes. Convertible senior notes aggregating $402 million remained outstanding at March 31, 2008. In April 2008, we issued 0.25 million shares of our common stock and paid cash of approximately $11 million to settle a conversion of approximately $11 million principal amount of our 3.75% convertible notes.

~~Arkansas Public Service Commission (APSC), Affiliate Transaction Rulemaking Proceeding.~~In ~~December 2006,~~April 2008, we announced a call for redemption of our 3.75% convertible senior notes, at 100% of their principal amount, on May 30, 2008. Substantially all of such notes are expected to be converted by holders prior to the ~~APSC adopted new rules governing affiliate transactions involving public utilities operating in Arkansas. In February 2007, in response~~redemption date, and substantially all of such conversions are expected to ~~requests by CERC~~be settled with a cash payment for the principal amount and ~~other gas and electric utilities operating in Arkansas,~~delivery of shares of our common stock for the ~~APSC granted reconsideration~~excess value due converting holders. If our closing stock price of $15.57 at April 25, 2008 were unchanged at the dates of the ~~rules and stayed their operation in order to permit additional consideration. The parties are awaiting~~conversions, assuming the ~~decision~~conversion of approximately $391 million aggregate principal amount of the ~~APSC following that reconsideration. As originally adopted,~~notes at the ~~rules could have adverse impacts on CERC’s ability~~current conversion rate, common stock reflecting a conversion premium of $153 million would be issued to ~~operate and provide cost-effective utility service in Arkansas. For example,~~ the rules would treat as affiliate transactions all transactions between CERC’s Arkansas utility operations and other divisions of CERC, as well as transactions between the Arkansas utility operations and affiliates of CERC. All such affiliate transactions would have toconverting holders. The conversion rate will be priced under an asymmetrical pricing formula under which the Arkansas utility operations would benefit from any difference between the cost of providing goods and services to or from the Arkansas utility operations and the market value of those goods or services. Additionally, the Arkansas utility operations would not be permitted to participate in any financing other than to finance retail utility operations in Arkansas, which would preclude continuation of existing financing arrangements in which CERC finances its divisions and subsidiaries, including its Arkansas utility operations.

~~If the rules are not satisfactorily modified~~increased as a result of our April 24, 2008 declaration of a regular quarterly cash dividend of $0.1825 per share. Under the reconsideration, CERC would be entitled to seek judicial review. If the rules ultimately become effective as originally adopted, CERC anticipates that it would need to seek waivers from certain provisionsterms of the ~~rules or would~~indenture governing the notes, the increased conversion rate will be ~~required to make significant modifications to existing practices, which could include the formation of and transfer of assets to subsidiaries.~~

If this regulatory framework becomes effective, it could adversely affect CERC’s ability to operate its utility and other businesses under its existing structure and to provide cost-effective utility service.determined on May 13, 2008.

Off-Balance Sheet Arrangements.Other than operating leases and the guaranties described below, we have no off-balance sheet arrangements.

Prior to the distribution of our ownership in Reliant Energy, Inc. (RRI) to our shareholders, CERC had guaranteed certain contractual obligations of what became RRI’s trading subsidiary. Under the terms of the separation agreement between the companies, RRI agreed to extinguish all such guaranty obligations prior to separation, but at the time of separation

in September 2002, RRI had been unable to extinguish all obligations. To secure ~~us and~~ CERC against obligations under the remaining guaranties, RRI agreed to provide cash or letters of credit for ~~the~~CERC’s benefit, ~~of CERC and us,~~ and undertook to use commercially reasonable efforts to extinguish the remaining guaranties. In December 2007, we, CERC ~~currently holds~~and RRI amended that agreement and CERC released the letters of credit it held as security. Under the revised agreement RRI agreed to provide cash or new letters of credit to secure CERC against exposure under the remaining guaranties as calculated under the new agreement if and to the extent changes in ~~the amount~~market conditions exposed CERC to a risk of ~~$33.3 million issued~~loss on ~~behalf~~those guaranties.

The potential exposure of ~~RRI against guaranties that have not been released. Our current exposure~~CERC under the guaranties relates to ~~CERC’s guaranty of the~~ payment ~~by RRI~~ of demand charges related to transportation ~~contracts with one counterparty. The demand charges are approximately $53 million per year through 2015, $49 million in 2016, $38 million in 2017 and $13 million in 2018.~~contracts. RRI continues to meet its obligations under the ~~transportation~~ contracts, and, ~~we believe~~on the basis of current market conditions, ~~make those contracts valuable for transportation services in the near term.~~we and CERC believe that additional security is not needed at this time. However, ~~changes in market conditions could affect the value of those contracts. If~~if RRI should fail to perform its obligations under the ~~transportation~~ contracts ~~our~~or if RRI should fail to provide adequate security in the event market conditions change adversely, we would retain exposure to the counterparty under the guaranty could exceed the security provided by RRI. We have requested RRI to increase the amount of its existing letters of credit or, in the alternative, to obtain a release of CERC’s obligations under the guaranty. In June 2006, the RRI trading subsidiary and CERC jointly filed a complaint at the Federal Energy Regulatory Commission (FERC) against the counterparty on the CERC guaranty. In the complaint, the RRI trading subsidiary seeks a determination by the FERC that the security demanded by the counterparty exceeds the level permitted by the FERC’s policies. The complaint asks the FERC to require the counterparty to release CERC from its guaranty obligation and, in its place, accept (i) a guaranty from RRI of the obligations of the RRI trading subsidiary, and (ii) letters of credit limited to (A) one year of demand charges for a transportation agreement related to a 2003 expansion of the counterparty’s pipeline, and (B) three months of demand charges for three other transportation agreements held by the RRI trading subsidiary. The counterparty has argued that the amount of the guaranty does not violate the FERC’s policies and that the proposed substitution of credit support is not authorized under the counterparty’s financing documents or required by the FERC’s policy. The parties have now completed their submissions to the FERC regarding the complaint. We cannot predict what action the FERC may take on the complaint or when the FERC may rule. In addition to the FERC proceeding, in February 2007 we and CERC made a formal demand on RRI under procedures provided for by the Master Separation Agreement, dated as of December 31, 2000, between Reliant Energy, Incorporated and RRI. That demand seeks to resolve the disagreement with RRI over the amount of security RRI is obligated to provide with respect to this guaranty. In conjunction with discussion of that demand, we and RRI entered into an agreement in March 2007 to delay further proceedings regarding this dispute until October 2007 in order to permit further discussions. It is possible that an arbitration proceeding between the companies could be pursued, but when and on what terms the disagreement with RRI will ultimately be resolved cannot be predicted.

Credit and Receivables Facilities.As of ~~May 1, 2007,~~March 31, 2008, we had the following facilities (in millions):

Amount Utilized at
Date Executed Company Type of Facility Size of Facility May 1, 2007 Termination Date
March 31, 2006 CenterPoint Energy Revolver $ 1,200 $ 28 ⁽¹⁾ March 31, 2011
March 31, 2006 CenterPoint Houston Revolver 300 4 ⁽¹⁾ March 31, 2011
March 31, 2006 CERC Corp. Revolver 550 19 ⁽¹⁾ March 31, 2011
October 31, 2006 CERC Receivables 375 269 October 30, 2007

Amount Utilized at

Date Executed

Company

Type of Facility

Size of Facility

March 31, 2008

Termination Date

June 29, 2007

CenterPoint Energy

Revolver

1,200

⁽¹⁾

June 29, 2012

June 29, 2007

CenterPoint Houston

Revolver

300

⁽¹⁾

June 29, 2012

June 29, 2007

CERC Corp.

Revolver

950

135

⁽²⁾

June 29, 2012

October 30, 2007

CERC

Receivables

375

200

October 28, 2008


(1)		Represents outstanding letters of credit.

(2)		Includes $100 million of borrowings under the credit facility and $35 million of outstanding commercial paper supported by the CERC Corp. credit facility.

Our $1.2 billion credit facility has a first drawn cost of London Interbank Offered Rate (LIBOR) plus 55 basis points based on our current credit ratings. The facility contains a debt (excluding transition bonds) to earnings before interest, taxes, depreciation and amortization covenant.

CenterPoint Houston’s $300 million credit facility’s first drawn cost is LIBOR plus 45 basis points based on CenterPoint Houston’s current credit ratings. The facility contains a debt (excluding transition bonds) to total capitalization covenant.

CERC Corp.’s $950 million credit facility’s first drawn cost is LIBOR plus 45 basis points based on CERC Corp.’s current credit ratings. The facility contains a debt to total capitalization covenant.

Under each of ~~our~~the credit facilities, an additional utilization fee of 105 basis points applies to borrowings any time more than 50% of the facility is ~~utilized,~~utilized. The spread to LIBOR and the ~~spread to London Interbank Offered Rate fluctuates~~utilization fee fluctuate based on the borrower’s credit rating. Borrowings under each of the facilities are subject to customary terms and conditions. However, there is no requirement that we, CenterPoint Houston or CERC Corp. make representations prior to borrowings as to the absence of material adverse changes or litigation that could be expected to have a material adverse effect. Borrowings under each of the credit facilities are subject to acceleration upon the occurrence of events of default that we, CenterPoint Houston or CERC Corp. consider customary.

The termination date of CERC’s receivables facility is in October 2007. The facility size is $375 million to May 2007 and ranges from $150 million to $325 million during the period from May 2007 to the October 30, 2007 termination date of the facility.

We, CenterPoint Houston and CERC Corp. are currently in compliance with the various business and financial covenants contained in the respective receivables and credit facilities.

~~The~~Our $1.2 billion ~~CenterPoint Energy~~ credit facility backstops a $1.0 billion CenterPoint Energy commercial paper program under which ~~CenterPoint Energy~~we began issuing commercial paper in June 2005. The $950 million CERC Corp. credit facility backstops a $950 million commercial paper program under which CERC Corp. began issuing commercial paper in February 2008. As of March 31, ~~2007,~~2008, there was no CenterPoint Energy commercial paper outstanding and $35 million of CERC Corp. commercial paper outstanding. The CenterPoint Energy commercial paper is rated “Not Prime” by Moody’s Investors Service, Inc. (Moody’s), “A-2” by Standard & Poor’s Rating Services (S&P), a division of The McGraw-Hill Companies, and “F3” by Fitch, Inc. (Fitch). The CERC Corp. commercial paper is rated “P-3” by Moody’s, “A-2” by S&P, and as“F2” by Fitch. As a result of the credit ratings on the two commercial paper programs, we do not expect to be able to rely on the sale of commercial paper to fund all of our short-term borrowing requirements. We cannot assure you that these ratings, or the credit ratings set forth below in “— Impact on Liquidity of a Downgrade in Credit Ratings,” will remain in effect for any given period of time or that one or more of these ratings will not be lowered or withdrawn entirely by a rating agency. We note that these credit ratings are not recommendations to buy, sell or hold our securities and may be revised or withdrawn at any time by the rating agency. Each rating should be evaluated independently of any other rating. Any future reduction or withdrawal of one or more of our credit ratings could have a material adverse impact on our ability to obtain short- and long-term financing, the cost of such financings and the execution of our commercial strategies.

Securities Registered with the SEC.As of March 31, ~~2007,~~2008, CenterPoint Energy had a shelf registration statement covering senior debt securities, preferred stock and common stock aggregating $750 million and CERC Corp. had a shelf registration statement covering ~~$350~~$400 million principal amount of senior debt securities.

~~Temporary Investments.~~Hedging of Future Debt Issuances.As of March 31, ~~2007,~~2008, we had outstanding treasury rate lock derivative instruments (treasury rate locks) with an aggregate notional amount of $300 million, expiration dates of June 2008 and a weighted-average locked U.S. treasury rate on ten-year debt of 4.05%. These treasury rate locks were executed to hedge the ten-year U.S. treasury rate expected to be used in pricing the forecasted issuance of $300 million of fixed-rate debt in 2008.

Temporary Investments. As of March 31, 2008, CERC Corp. had external temporary investments of approximately ~~$6 million. As of May 1, 2007, we had external temporary investments of $16~~$4 million.

Money Pool.We have a money pool through which the holding company and participating subsidiaries can borrow or invest on a short-term basis. Funding needs are aggregated and external borrowing or investing is based on the net cash position. The net funding requirements of the money pool are expected to be met with borrowings under ~~CenterPoint Energy’s~~our revolving credit facility or the sale of our commercial paper.

Impact on Liquidity of a Downgrade in Credit Ratings.As of ~~May 1, 2007,~~April 15, 2008, Moody’s, S&P, and Fitch had assigned the following credit ratings to senior debt of CenterPoint Energy and certain subsidiaries:

~~Moody's~~Moody’s

S&P

Fitch

Company/Instrument

Rating

Outlook(1)

Rating

Outlook(2)

Rating

Outlook(3)

CenterPoint Energy Senior Unsecured
Debt

Ba1

Stable

BBB-

~~Positive~~Stable

BBB-

Stable

CenterPoint Houston Senior Secured
Debt (First Mortgage Bonds)

Baa2

Stable

~~BBB~~BBB+

~~Positive~~Stable

A-

Stable

CERC Corp. Senior Unsecured Debt

Baa3

Stable

BBB

~~Positive~~Stable

BBB

Stable


(1)		A “stable” outlook from Moody’s indicates that Moody’s does not expect to put the rating on review for an upgrade or downgrade within 18 months from when the outlook was assigned or last affirmed.

(2)		An S&P rating outlook assesses the potential direction of a long-term credit rating over the intermediate to longer term.

(3)		A “stable” outlook from Fitch encompasses a ~~one-to-two-year~~one- to two-year horizon as to the likely ratings direction.

A decline in credit ratings could increase borrowing costs under our $1.2 billion credit facility, CenterPoint Houston’s $300 million credit facility and CERC Corp.’s ~~$550~~$950 million credit facility. A decline in credit ratings would also increase the interest rate on long-term debt to be issued in the capital markets and could negatively impact our ability to complete capital market transactions. Additionally, a decline in credit ratings could increase cash collateral requirements and reduce ~~margins~~earnings of our Natural Gas Distribution and Competitive Natural Gas Sales and Services business segments.

In September 1999, we issued 2.0% ZENS having an original principal amount of $1.0 billion of which $840 million remain outstanding. Each ZENS note is exchangeable at the holder’s option at any time for an amount of cash equal to 95% of the market value of the reference shares of Time Warner Inc. common stock (TW Common) attributable to each ZENS note. If our creditworthiness were to drop such that ZENS note holders thought our liquidity was adversely affected or the market for the ZENS notes were to become illiquid, some ZENS note holders might decide to exchange their ZENS notes for cash. Funds for the payment of cash upon exchange could be obtained from the sale of the shares of TW Common that we own or from other sources. We own shares of TW

Common equal to approximately 100% of the reference shares used to calculate our obligation to the holders of the ZENS notes. ZENS note exchanges result in a cash outflow because deferred tax liabilities related to the ZENS notes and TW Common shares become current tax obligations when ZENS notes are exchanged or otherwise retired and TW Common shares are sold. A tax obligation of approximately ~~$132~~$158 million relating to our “original issue discount” deductions on the ZENS would have been payable if all of the ZENS had been exchanged for cash on March 31, ~~2007.~~2008. The ultimate tax obligation related to the ZENS notes continues to increase by the amount of the tax benefit realized each year and there could be a significant cash outflow when the taxes are paid as a result of the retirement of the ZENS notes.

CenterPoint Energy Services, Inc. (CES), a wholly owned subsidiary of CERC Corp. operating in our Competitive Natural Gas Sales and Services business segment, provides comprehensive natural gas sales and services primarily to commercial and industrial customers and electric and gas utilities throughout the central and eastern United States. In order to economically hedge its exposure to natural gas prices, CES uses derivatives with provisions standard for the industry, including those pertaining to credit thresholds. Typically, the credit threshold negotiated with each counterparty defines the amount of unsecured credit that such counterparty will extend to CES. To the extent that the credit exposure that a counterparty has to CES at a particular time does not exceed that credit threshold, CES is not obligated to provide collateral. Mark-to-market exposure in excess of the credit threshold is routinely collateralized by CES. As of March 31, ~~2007,~~2008, the amount posted as collateral amounted to approximately ~~$61~~$20 million. Should the credit ratings of CERC Corp. ~~(the~~(as the credit support provider for CES) fall below certain levels, CES would be required to provide additional collateral on two business days’ notice up to the amount of its previously unsecured credit limit. We estimate that as of March 31, ~~2007,~~2008, unsecured credit limits extended to CES by counterparties aggregate ~~$133~~$180 million; however, utilized credit capacity is significantly lower. In addition, CERC Corp. and its subsidiaries purchase natural gas under supply agreements that contain an aggregate credit threshold of ~~$100~~

$100 million based on CERC Corp.’s S&P Senior Unsecured Long-Term Debt rating of BBB. Upgrades and downgrades from this BBB rating will increase and decrease the aggregate credit threshold accordingly.

In connection with the development of SESH’s ~~270 mile~~270-mile pipeline project, CERC Corp. has committed that it will advance funds to the joint venture or cause funds to be advanced ~~up to $400 million,~~ for its ~~50 percent~~50% share of the cost to construct the pipeline. CERC Corp. also agreed to provide a letter of credit in ~~the~~an amount ofup to $400 million for its share of funds that have not been advanced in the event S&P reduces CERC Corp.’s bond rating below investment grade before CERC Corp. has advanced the required construction funds. However, CERC Corp. is relieved of these commitments (i) to the extent of ~~50 percent~~50% of any borrowing agreements that the joint venture has obtained and maintains for funding the construction of the pipeline and (ii) to the extent CERC Corp. or its subsidiary participating in the joint venture obtains committed borrowing agreements pursuant to which funds may be borrowed and used for the construction of the pipeline. A similar commitment has been provided by the other party to the joint venture. As of March 31, ~~2007,~~2008, subsidiaries of CERC Corp.~~’s subsidiary, CenterPoint Energy Southeastern Pipelines Holding, LLC, has funded $25~~ have advanced approximately $305 million to ~~SESH.~~SESH, of which $159 million was in the form of an equity contribution and $146 million was in the form of a loan.

Cross Defaults.Under our revolving credit facility, a payment default on, or a non-payment default that permits acceleration of, any indebtedness exceeding $50 million by us or any of our significant subsidiaries will cause a default. In addition, six outstanding series of our senior notes, aggregating ~~$1.4~~$1.3 billion in principal amount as of March 31, ~~2007,~~2008, provide that a payment default by us, CERC Corp. or CenterPoint Houston in respect of, or an acceleration of, borrowed money and certain other specified types of obligations, in the aggregate principal amount of $50 million, will cause a default. A default by CenterPoint Energy would not trigger a default under our subsidiaries’ debt instruments or bank credit facilities.

Other Factors that Could Affect Cash Requirements.In addition to the above factors, our liquidity and capital resources could be affected by:

	•		cash collateral requirements that could exist in connection with certain contracts, including gas purchases, gas price and weather hedging and gas storage activities of our Natural Gas Distribution and Competitive Natural Gas Sales and Services business segments, particularly given gas price levels and volatility;

	•		acceleration of payment dates on certain gas supply contracts under certain circumstances, as a result of increased gas prices and concentration of natural gas suppliers;

	•		increased costs related to the acquisition of natural gas;

Certain Contractual Limits on Our Ability to Issue Securities and Borrow Money.CenterPoint Houston’s credit facility limits CenterPoint Houston’s debt (excluding transition bonds) as a percentage of its total capitalization to ~~65 percent.~~65%. CERC Corp.’s bank facility and its receivables facility limit CERC’s debt as a percentage of its total capitalization to ~~65 percent.~~65%. Our $1.2 billion credit facility contains a debt, excluding transition bonds, to EBITDA covenant. Additionally, CenterPoint Houston ishas contractually ~~prohibited,~~agreed that it will not issue additional first mortgage bonds, subject to certain ~~exceptions, from issuing additional first mortgage bonds.~~

~~CRITICAL ACCOUNTING POLICIES~~

A critical accounting policy is one that is both important to the presentation of our financial condition and results of operations and requires management to make difficult, subjective or complex accounting estimates. An accounting estimate is an approximation made by management of a financial statement element, item or account in the financial statements. Accounting estimates in our historical consolidated financial statements measure the effects of past business transactions or events, or the present status of an asset or liability. The accounting estimates described below require us to make assumptions about matters that are highly uncertain at the time the estimate is made. Additionally, different estimates that we could have used or changes in an accounting estimate that are reasonably likely to occur could have a material impact on the presentation of our financial condition or results of operations. The circumstances that make these judgments difficult, subjective and/or complex have to do with the need to make estimates about the effect of matters that are inherently uncertain. Estimates and assumptions about future events and their effects cannot be predicted with certainty. We base our estimates on historical experience and on various other assumptions that we believe to be reasonable under the circumstances, the results of which form the basis for making judgments. These estimates may change as new events occur, as more experience is acquired, as additional information is obtained and as our operating environment changes. Our significant accounting policies are discussed in Note 2 to our consolidated financial statements in our 2006 Form 10-K. We believe the following accounting policies involve the application of critical accounting estimates. Accordingly, these accounting estimates have been reviewed and discussed with the audit committee of the board of directors.

~~Accounting for Rate Regulation~~

SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation” (SFAS No. 71), provides that rate-regulated entities account for and report assets and liabilities consistent with the recovery of those incurred costs in rates if the rates established are designed to recover the costs of providing the regulated service and if the competitive environment makes it probable that such rates can be charged and collected. Our Electric Transmission & Distribution business applies SFAS No. 71, which results in our accounting for the regulatory effects of recovery of stranded costs and other regulatory assets resulting from the unbundling of the transmission and distribution business from our former electric generation operations in our consolidated financial statements.

Certain expenses and revenues subject to utility regulation or rate determination normally reflected in income are deferred on the balance sheet and are recognized in income as the related amounts are included in service rates and recovered from or refunded to customers. Significant accounting estimates embedded within the application of SFAS No. 71 with respect to our Electric Transmission & Distribution business segment relate to $292 million of recoverable electric generation-related regulatory assets as of March 31, 2007. These costs are recoverable under the provisions of the 1999 Texas Electric Choice Plan. Based on our analysis of the final order issued by the Public Utility Commission of Texas (Texas Utility Commission), we recorded an after-tax charge to earnings in 2004 of approximately $977 million to write down our electric generation-related regulatory assets to their realizable value, which was reflected as an extraordinary loss. Based on subsequent orders received from the Texas Utility Commission, we recorded an extraordinary gain of $30 million after-tax in the second quarter of 2005 related to the regulatory asset. Additionally, a district court in Travis County, Texas issued a judgment that would have the effect of restoring approximately $650 million, plus interest, of disallowed costs. CenterPoint Houston and other parties appealed the district court judgment. Oral arguments before the Texas 3rd Court of Appeals were held in January 2007, but a decision is not expected for several months. No amounts related to the district court’s judgment have been recorded in our consolidated financial statements.

~~Impairment of Long-Lived Assets and Intangibles~~

We review the carrying value of our long-lived assets, including goodwill and identifiable intangibles, whenever events or changes in circumstances indicate that such carrying values may not be recoverable, and at least annually for goodwill as required by SFAS No. 142, “Goodwill and Other Intangible Assets.” No impairment of goodwill was indicated based on our annual analysis as of July 1, 2006. Unforeseen events and changes in circumstances and market conditions and material differences in the value of long-lived assets and intangibles due to changes in estimates of future cash flows, regulatory matters and operating costs could negatively affect the fair value of our assets and result in an impairment charge.

Fair value is the amount at which the asset could be bought or sold in a current transaction between willing parties and may be estimated using a number of techniques, including quoted market prices or valuations by third parties, present value techniques based on estimates of cash flows, or multiples of earnings or revenue performance measures. The fair value of the asset could be different using different estimates and assumptions in these valuation techniques.

~~Asset Retirement Obligations~~

We account for our long-lived assets under SFAS No. 143, “Accounting for Asset Retirement Obligations” (SFAS No. 143), and Financial Accounting Standards Board Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations — An Interpretation of SFAS No. 143” (FIN 47). SFAS No. 143 and FIN 47 require that an asset retirement obligation be recorded at fair value in the period in which it is incurred if a reasonable estimate of fair value can be made. In the same period, the associated asset retirement costs are capitalized as part of the carrying amount of the related long-lived asset. Rate-regulated entities may recognize regulatory assets or liabilities as a result of timing differences between the recognition of costs as recorded in accordance with SFAS No. 143 and FIN 47, and costs recovered through the ratemaking process.

~~We estimate the fair value of asset retirement obligations by calculating the discounted cash flows that are dependent upon the following components:~~

	•		~~Inflation adjustment — The estimated cash flows are adjusted for inflation estimates for labor, equipment, materials, and other disposal costs;~~

	•		~~Discount rate — The estimated cash flows include contingency factors that were used as a proxy for the market risk premium; and~~

	•		Third-party markup adjustments — Internal labor costs included in the cash flow calculation were adjusted for costs that a third party would incur in performing the tasks necessary to retire the asset.

Changes in these factors could materially affect the obligation recorded to reflect the ultimate cost associated with retiring the assets under SFAS No. 143 and FIN 47. For example, if the inflation adjustment increased 25 basis points, this would increase the balance for asset retirement obligations by approximately 3.0%. Similarly, an

increase in the discount rate by 25 basis points would decrease asset retirement obligations by approximately the same percentage. At March 31, 2007, our estimated cost of retiring these assets is approximately $86 million.

~~Unbilled Energy Revenues~~

Revenues related to the sale and/or delivery of electricity or natural gas (energy) are generally recorded when energy is delivered to customers. However, the determination of energy sales to individual customers is based on the reading of their meters, which is performed on a systematic basis throughout the month. At the end of each month, amounts of energy delivered to customers since the date of the last meter reading are estimated and the corresponding unbilled revenue is estimated. Unbilled electricity delivery revenue is estimated each month based on daily supply volumes, applicable rates and analyses reflecting significant historical trends and experience. Unbilled natural gas sales are estimated based on estimated purchased gas volumes, estimated lost and unaccounted for gas and tariffed rates in effect. As additional information becomes available, or actual amounts are determinable, the recorded estimates are revised. Consequently, operating results can be affected by revisions to prior accounting estimates.

~~Pension and Other Retirement Plans~~

We sponsor pension and other retirement plans in various forms covering all employees who meet eligibility requirements. We use several statistical and other factors that attempt to anticipate future events in calculating the expense and liability related to our plans. These factors include assumptions about the discount rate, expected return on plan assets and rate of future compensation increases as estimated by management, within certain guidelines. In addition, our actuarial consultants use subjective factors such as withdrawal and mortality rates. The actuarial assumptions used may differ materially from actual results due to changing market and economic conditions, higher or lower withdrawal rates or longer or shorter life spans of participants. These differences may result in a significant impact to the amount of pension expense recorded. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations— Other Significant Matters — Pension Plan” in Item 7 of our 2006 Form 10-K for further discussion.exceptions.

NEWACCOUNTING PRONOUNCEMENTS

See Note 2 to our Interim Condensed Financial Statements for a discussion of new accounting pronouncements that affect us.

Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Commodity Price Risk From Non-Trading Activities

We use derivative instruments as economic hedges to offset the commodity price exposure inherent in our businesses. The stand-alone commodity risk created by these instruments, without regard to the offsetting effect of the underlying exposure these instruments are intended to hedge, is described below. We measure the commodity risk of our non-trading energy derivatives ~~(Non-Trading Energy Derivatives)~~ using a sensitivity analysis.

The sensitivity analysis performed on our non-trading energy derivatives measures the potential loss in fair value based on a hypothetical 10% movement in energy prices. At March 31, ~~2007,~~2008, the recorded fair value of our non-trading energy derivatives was a net ~~liability~~asset of ~~$26~~$61 million. The net ~~liability~~asset consisted of a ~~$40~~net asset of less than $1 million ~~net liability~~ associated with price stabilization activities of our Natural Gas Distribution business segment ~~partially offset by~~and a net asset of ~~$14~~$60 million related to our Competitive Natural Gas Sales and Services business segment. Net assets or liabilities related to the price stabilization activities correspond directly with net over/under recovered gas cost liabilities or assets on the balance sheet. A decrease of 10% in the market prices of energy commodities from their March 31, ~~2007~~2008 levels would have decreased the fair value of our non-trading energy derivatives net asset by $6$12 million.

The above analysis of the ~~Non-Trading Energy Derivatives~~non-trading energy derivatives utilized for commodity price risk management purposes does not include the favorable impact that the same hypothetical price movement would have on our physical purchases and sales of natural gas to which the hedges relate. Furthermore, the ~~Non-Trading Energy Derivative~~non-trading energy derivative portfolio is managed to complement the physical transaction portfolio, reducing overall risks within limits. Therefore, the adverse impact to the fair value of the portfolio of ~~Non-Trading Energy Derivatives~~non-trading energy derivatives held for hedging purposes associated with the hypothetical changes in commodity prices referenced above is expected to be substantially offset by a favorable impact on the underlying hedged physical transactions.

Interest Rate Risk

~~We have~~As of March 31, 2008, we had outstanding long-term debt, bank loans, ~~some~~ lease obligations, treasury rate lock derivative instruments and ~~our~~ obligations under ~~the~~our ZENS that subject us to the risk of loss associated with movements in market interest rates.

Our floating-rate obligations aggregated ~~$337~~$335 million at March 31, ~~2007.~~2008. If the floating interest rates were to increase by 10% from March 31, ~~2007~~2008 rates, our ~~annual~~combined interest expense would increase by approximately ~~$2 million.~~$1 million annually.

At March 31, ~~2007,~~2008, we had outstanding fixed-rate debt (excluding indexed debt securities) aggregating ~~$9.0~~$9.2 billion in principal amount and having a fair value of ~~$9.5~~$9.4 billion. These instruments are fixed-rate and, therefore, do not expose us to the risk of loss in earnings due to changes in market interest ~~rates.~~rates (please read Note 9 to our consolidated financial statements). However, the fair value of these instruments would increase by approximately ~~$403~~$379 million if interest rates were to decline by 10% from their levels at March 31, ~~2007.~~2008. In general, such an increase in fair value would impact earnings and cash flows only if we were to reacquire all or a portion of these instruments in the open market prior to their maturity.

~~Upon adoption~~As of March 31, 2008, we had outstanding treasury rate locks with an aggregate notional amount of $300 million, expiration dates of June 2008 and a weighted-average locked U.S. treasury rate on ten-year debt of 4.05%.

These treasury rate locks were executed to hedge the ten-year U.S. treasury rate expected to be used in pricing the forecasted issuance of $300 million of fixed-rate debt in 2008. As of March 31, 2008, the treasury lock derivative instruments could be terminated at a cost of $16 million. The treasury rate locks qualify as cash flow hedges under SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” (SFAS No. 133), and are marked to market in our Consolidated Balance Sheets with changes reflected in accumulated other comprehensive loss. A decrease of 10% in the March 31, 2008 level of interest rates on 10-year U.S. treasury notes would increase the cost of terminating the treasury rate locks outstanding at March 31, 2008 by approximately $9 million.

Upon adoption of SFAS No. 133, effective January 1, 2001, the ZENS obligation was bifurcated into a debt component and a derivative component. The debt component of ~~$112~~$115 million at March 31, ~~2007 is~~2008 was a fixed-rate obligation and, therefore, ~~does~~did not expose us to the risk of loss in earnings due to changes in market interest rates. However, the fair value of the debt component would increase by approximately ~~$18~~$19 million if interest rates were to decline by 10% from levels at March 31, ~~2007.~~2008. Changes in the fair value of the derivative component, ~~will be~~a $211 million recorded liability at March 31, 2008, are recorded in our ~~Condensed~~ Statements of Consolidated Income and, therefore, we are exposed to changes in the fair value of the derivative component as a result of changes in the underlying risk-free interest rate. If the risk-free interest rate were to increase by 10% from March 31, ~~2007~~2008 levels, the fair value of the derivative component liability would increase by approximately $6$3 million, which would be recorded as aan unrealized loss in our ~~Condensed~~ Statements of Consolidated Income.

Equity Market Value Risk

We are exposed to equity market value risk through our ownership of 21.6 million shares of TW Common, which we hold to facilitate our ability to meet our obligations under the ZENS. A decrease of 10% from the March 31, ~~2007~~2008 market value of TW Common would result in a net loss of approximately $4 million, which would be recorded as aan unrealized loss in our ~~Condensed~~ Statements of Consolidated Income.

Item 4. CONTROLS AND PROCEDURES

In accordance with Exchange Act Rules 13a-15 and 15d-15, we carried out an evaluation, under the supervision and with the participation of management, including our principal executive officer and principal financial officer, of the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report. Based on that evaluation, our principal executive officer and principal financial officer concluded that our disclosure controls and procedures were effective as of March 31, ~~2007~~2008 to provide assurance that information required to be disclosed in our reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms and such information is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate to allow timely decisions regarding disclosure.

There has been no change in our internal controls over financial reporting that occurred during the three months ended March 31, ~~2007~~2008 that has materially affected, or is reasonably likely to materially affect, our internal controls over financial reporting.

Item 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

Conversion of 3.75% Convertible Senior Notes due 2023.Since February 20, 2008, we have issued 533,737 shares of our common stock upon conversion of approximately $21.4 million aggregate principal amount of our 3.75% Convertible Senior Notes due 2023, as set forth in the table below:


Settlement Date	Principal Amount		Number of Shares
of Conversion	of Notes Converted		of Common Stock Issued
March 7, 2008	$	650,000		58,134	(1)
March 12, 2008		10,000,000		227,803	(2)
April 18, 2008		2,000		44	(2)
April 21, 2008		2,000		45	(2)
April 22, 2008		10,718,000		247,664	(2)
April 25, 2008		2,000		47	(2)

	$	21,374,000		533,737


(1)		Based on terms of the notes, settled entirely through the issuance of shares except for a payment of cash in lieu of fractional shares.

(2)		The number of shares issued in respect of any principal amount of notes converted is in addition to payment of cash in an amount equal to the principal amount of such notes and cash in lieu of fractional shares.

The shares of our common stock were issued solely to former holders of our 3.75% Convertible Senior Notes due 2023 upon conversion pursuant to the exemption from registration provided under Section 3(a)(9) of the Securities Act of 1933, as amended. This exemption is available because the shares of our common stock were exchanged by us with our existing security holders exclusively where no commission or other remuneration was paid or given directly or indirectly for soliciting such an exchange.

Item 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

At the annual meeting of our shareholders held on April 24, 2008, the matters voted upon and the number of votes cast for or against, as well as the number of abstentions and broker non-votes as to such matters (including a separate tabulation with respect to each nominee for office), were as stated below:

The following nominees for Class III Directors were elected to serve three-year terms expiring at the 2011 annual meeting of shareholders (abstentions and broker non-votes were not counted):


Nominee	For		Against
O. Holcombe Crosswell		272,278,964		5,954,739

Janiece M. Longoria		273,426,876		4,863,309

Thomas F. Madison		270,543,888		7,520,236

Sherman M. Wolff		272,791,233		5,358,604

Derrill Cody, David M. McClanahan, Robert T. O’Connell, Michael E. Shannon, Donald R. Campbell, Milton Carroll and Peter S. Wareing all continue as directors of CenterPoint Energy.

The proposal to amend our Articles of Incorporation to phase out our board of directors’ classified structure was approved with 270,351,324 votes for, 7,301,896 votes against, 3,980,338 abstentions and no broker non-votes.

The appointment of Deloitte & Touche LLP as independent registered public accountants for CenterPoint Energy for 2008 was ratified with 274,156,719 votes for, 4,013,996 votes against, 3,462,844 abstentions and no broker non-votes.

Item 6. EXHIBITS

The following exhibits are filed herewith:

Exhibits not incorporated by reference to a prior filing are designated by a cross (+); all exhibits not so designated are incorporated by reference to a prior filing of CenterPoint Energy, Inc.


					SEC File												SEC File
					or												or
Exhibit					Registration		Exhibit			Exhibit							Registration		Exhibit
Number		Description		Number		Reference			Number			Description		Report or Registration Statement		Number		Reference
3.1.1	—	Amended and Restated Articles of Incorporation of CenterPoint Energy	CenterPoint Energy’s Registration Statement on Form S-4		3-69502			3.1			—		Amended and Restated Articles of Incorporation of CenterPoint Energy		CenterPoint Energy’s Registration Statement on Form S-4		3-69502			3.1

3.1.2	—	Articles of Amendment to Amended and Restated Articles of Incorporation of CenterPoint Energy	CenterPoint Energy’s Form 10-K for the year ended December 31, 2001		1-31447			3.1.1			—		Articles of Amendment to Amended and Restated Articles of Incorporation of CenterPoint Energy dated March 27, 2002		CenterPoint Energy’s Form 10-K for the year ended December 31, 2001		1-31447			3.1.1

+3.1.3											—		Articles of Amendment to Amended and Restated Articles of Incorporation of CenterPoint Energy dated April 24, 2008

3.2	—	Amended and Restated Bylaws of CenterPoint Energy	CenterPoint Energy’s Form 10-K for the year ended December 31, 2001		1-31447			3.2			—		Amended and Restated Bylaws of CenterPoint Energy		CenterPoint Energy’s Form 8-K dated January 24, 2008		1-31447			3.1

3.3	—	Statement of Resolution Establishing Series of Shares designated Series A Preferred Stock of CenterPoint Energy	CenterPoint Energy’s Form 10-K for the year ended December 31, 2001		1-31447			3.3			—		Statement of Resolution Establishing Series of Shares designated Series A Preferred Stock of CenterPoint Energy		CenterPoint Energy’s Form 10-K for the year ended December 31, 2001		1-31447			3.3

4.1	—	Form of CenterPoint Energy Stock Certificate	CenterPoint Energy’s Registration Statement on Form S-4		3-69502			4.1			—		Form of CenterPoint Energy Stock Certificate		CenterPoint Energy’s Registration Statement on Form S-4		3-69502			4.1

4.2	—	Rights Agreement dated January 1, 2002, between CenterPoint Energy and JPMorgan Chase Bank, as Rights Agent	CenterPoint Energy’s Form 10-K for the year ended December 31, 2001		1-31447			4.2			—		Rights Agreement dated January 1, 2002, between CenterPoint Energy and JPMorgan Chase Bank, as Rights Agent		CenterPoint Energy’s Form 10-K for the year ended December 31, 2001		1-31447			4.2

4.3	—	$1,200,000,000 Amended and Restated Credit Agreement dated as of March 31, 2006, among CenterPoint Energy, as Borrower, and the banks named therein	CenterPoint Energy’s Form 8-K dated March 31, 2006		1-31447			4.1			—		$1,200,000,000 Second Amended and Restated Credit Agreement, dated as of June 29, 2007, among CenterPoint Energy, as Borrower, and the banks named therein		CenterPoint Energy’s Form 10-Q for the quarter ended June 30, 2007		1-31447			4.3

4.4	—	$300,000,000 Amended and Restated Credit Agreement dated as of March 31, 2006, among CenterPoint Houston, as Borrower, and the Initial Lenders named therein, as Initial Lenders	CenterPoint Energy’s Form 8-K dated March 31, 2006		1-31447			4.2			—		$300,000,000 Second Amended and Restated Credit Agreement, dated as of June 29, 2007, among CenterPoint Houston, as Borrower, and the banks named therein		CenterPoint Energy’s Form 10-Q for the quarter ended June 30, 2007		1-31447			4.4

4.5	—	$550,000,000 Amended and Restated Credit Agreement dated as of March 31, 2006 among CERC Corp., as Borrower, and the banks named therein	CenterPoint Energy’s Form 8-K dated March 31, 2006		1-31447			4.3			—		$950,000,000 Second Amended and Restated Credit Agreement, dated as of June 29, 2007 among CERC Corp., as Borrower, and the banks named therein		CenterPoint Energy’s Form 10-Q for the quarter ended June 30, 2007		1-31447			4.5

4.6	—	Indenture, dated as of February 1, 1998, between Reliant Energy Resources Corp. and Chase Bank of Texas, National Association, as Trustee	CERC Corp.’s Form 8-K dated February 5, 1998		1-13265			4.1

4.7	—	Supplemental Indenture No. 10 to Exhibit 4.6, dated as of February 6, 2007, providing for the issuance of CERC Corp.’s 6.25% Senior Notes due 2037	CenterPoint Energy’s Form 10-K for the year ended December 31, 2006		1-31447			4(f	)(11)

4.8	—	Indenture, dated as of May 19, 2003, between CenterPoint Energy and JPMorgan Chase Bank, as Trustee	CenterPoint Energy’s Form 8-K dated May 19, 2003		1-31447			4.1


					SEC File												SEC File
					or												or
Exhibit					Registration		Exhibit			Exhibit							Registration		Exhibit
Number		Description		Number		Reference			Number			Description		Report or Registration Statement		Number		Reference
4.9	—	Supplemental Indenture No. 7 to Exhibit 4.8, dated as of February 6, 2007, providing for the issuance of CenterPoint Energy’s 5.95% Senior Notes due 2017	CenterPoint Energy’s Form 10-K for the year ended December 31, 2006		1-31447			4(g	)(8)

10.1	—	Form of Performance Share Award Agreement for 20XX — 20XX Performance Cycle under the Long-Term Incentive Plan of CenterPoint Energy, Inc.	CenterPoint Energy’s Form 8-K dated February 21, 2007		1-31447			10.1			—		Form of Performance Share Award Agreement for 20XX — 20XX Performance Cycle under the Long-Term Incentive Plan of CenterPoint Energy, Inc.		CenterPoint Energy’s Form 8-K dated February 20, 2008		1-31447			10.1

10.2	—	Form of Stock Award Agreement (With Performance Goal) under the Long-Term Incentive Plan of CenterPoint Energy, Inc.	CenterPoint Energy’s Form 8-K dated February 21, 2007		1-31447			10.2			—		Form of Stock Award Agreement (With Performance Goal) under the Long-Term Incentive Plan of CenterPoint Energy, Inc.		CenterPoint Energy’s Form 8-K dated February 20, 2008		1-31447			10.2

10.3	—	Form of Stock Award Agreement (Without Performance Goal) under the Long-Term Incentive Plan of CenterPoint Energy, Inc.	CenterPoint Energy’s Form 8-K dated February 21, 2007		1-31447			10.3			—		First Amendment to CenterPoint Energy, Inc. Deferred Compensation Plan (as amended and restated effective January 1, 2003)		CenterPoint Energy’s Form 8-K dated February 20, 2008		1-31447			10.3

10.4	—	Form of Change in Control Agreement.	CenterPoint Energy’s Form 8-K dated February 21, 2007		1-31447			10.4			—		CenterPoint Energy 2005 Deferred Compensation Plan (effective January 1, 2008)		CenterPoint Energy’s Form 8-K dated February 20, 2008		1-31447			10.3

+10.5	—	First Amendment, effective January 1, 2007, to Long-Term Incentive Plan of CenterPoint Energy, Inc.

+12	—	Computation of Ratios of Earnings to Fixed Charges									—		Computation of Ratios of Earnings to Fixed Charges

+31.1	—	Rule 13a-14(a)/15d-14(a) Certification of David M. McClanahan									—		Rule 13a-14(a)/15d-14(a) Certification of David M. McClanahan

+31.2	—	Rule 13a-14(a)/15d-14(a) Certification of Gary L. Whitlock									—		Rule 13a-14(a)/15d-14(a) Certification of Gary L. Whitlock

+32.1	—	Section 1350 Certification of David M. McClanahan									—		Section 1350 Certification of David M. McClanahan

+32.2	—	Section 1350 Certification of Gary L. Whitlock									—		Section 1350 Certification of Gary L. Whitlock

+99.1	—	Items incorporated by reference from the CenterPoint Energy Form 10-K. Item 1A “Risk Factors”									—		Items incorporated by reference from the CenterPoint Energy Form 10-K. Item 1A “Risk Factors”

EXHIBIT INDEX

~~Exhibits not incorporated by reference to a prior filing are designated by a cross (+); all exhibits not so designated are incorporated by reference to a prior filing of CenterPoint Energy, Inc.~~


					SEC File												SEC File
					or												or
Exhibit					Registration		Exhibit			Exhibit							Registration		Exhibit
Number		Description		Number		Reference			Number			Description		Report or Registration Statement		Number		Reference
3.1.1	—	Amended and Restated Articles of Incorporation of CenterPoint Energy	CenterPoint Energy’s Registration Statement on Form S-4		3-69502			3.1			—		Amended and Restated Articles of Incorporation of CenterPoint Energy		CenterPoint Energy’s Registration Statement on Form S-4		3-69502			3.1

3.1.2	—	Articles of Amendment to Amended and Restated Articles of Incorporation of CenterPoint Energy	CenterPoint Energy’s Form 10-K for the year ended December 31, 2001		1-31447			3.1.1			—		Articles of Amendment to Amended and Restated Articles of Incorporation of CenterPoint Energy dated March 27, 2002		CenterPoint Energy’s Form 10-K for the year ended December 31, 2001		1-31447			3.1.1

+3.1.3											—		Articles of Amendment to Amended and Restated Articles of Incorporation of CenterPoint Energy dated April 24, 2008

3.2	—	Amended and Restated Bylaws of CenterPoint Energy	CenterPoint Energy’s Form 10-K for the year ended December 31, 2001		1-31447			3.2			—		Amended and Restated Bylaws of CenterPoint Energy		CenterPoint Energy’s Form 8-K dated January 24, 2008		1-31447			3.1

3.3	—	Statement of Resolution Establishing Series of Shares designated Series A Preferred Stock of CenterPoint Energy	CenterPoint Energy’s Form 10-K for the year ended December 31, 2001		1-31447			3.3			—		Statement of Resolution Establishing Series of Shares designated Series A Preferred Stock of CenterPoint Energy		CenterPoint Energy’s Form 10-K for the year ended December 31, 2001		1-31447			3.3

4.1	—	Form of CenterPoint Energy Stock Certificate	CenterPoint Energy’s Registration Statement on Form S-4		3-69502			4.1			—		Form of CenterPoint Energy Stock Certificate		CenterPoint Energy’s Registration Statement on Form S-4		3-69502			4.1

4.2	—	Rights Agreement dated January 1, 2002, between CenterPoint Energy and JPMorgan Chase Bank, as Rights Agent	CenterPoint Energy’s Form 10-K for the year ended December 31, 2001		1-31447			4.2			—		Rights Agreement dated January 1, 2002, between CenterPoint Energy and JPMorgan Chase Bank, as Rights Agent		CenterPoint Energy’s Form 10-K for the year ended December 31, 2001		1-31447			4.2

4.3	—	$1,200,000,000 Amended and Restated Credit Agreement dated as of March 31, 2006, among CenterPoint Energy, as Borrower, and the banks named therein	CenterPoint Energy’s Form 8-K dated March 31, 2006		1-31447			4.1			—		$1,200,000,000 Second Amended and Restated Credit Agreement, dated as of June 29, 2007, among CenterPoint Energy, as Borrower, and the banks named therein		CenterPoint Energy’s Form 10-Q for the quarter ended June 30, 2007		1-31447			4.3

4.4	—	$300,000,000 Amended and Restated Credit Agreement dated as of March 31, 2006, among CenterPoint Houston, as Borrower, and the Initial Lenders named therein, as Initial Lenders	CenterPoint Energy’s Form 8-K dated March 31, 2006		1-31447			4.2			—		$300,000,000 Second Amended and Restated Credit Agreement, dated as of June 29, 2007, among CenterPoint Houston, as Borrower, and the banks named therein		CenterPoint Energy’s Form 10-Q for the quarter ended June 30, 2007		1-31447			4.4

4.5	—	$550,000,000 Amended and Restated Credit Agreement dated as of March 31, 2006 among CERC Corp., as Borrower, and the banks named therein	CenterPoint Energy’s Form 8-K dated March 31, 2006		1-31447			4.3			—		$950,000,000 Second Amended and Restated Credit Agreement, dated as of June 29, 2007 among CERC Corp., as Borrower, and the banks named therein		CenterPoint Energy’s Form 10-Q for the quarter ended June 30, 2007		1-31447			4.5

4.6	—	Indenture, dated as of February 1, 1998, between Reliant Energy Resources Corp. and Chase Bank of Texas, National Association, as Trustee	CERC Corp.’s Form 8-K dated February 5, 1998		1-13265			4.1

4.7	—	Supplemental Indenture No. 10 to Exhibit 4.6, dated as of February 6, 2007, providing for the issuance of CERC Corp.’s 6.25% Senior Notes due 2037	CenterPoint Energy’s Form 10-K for the year ended December 31, 2006		1-31447			4(f	)(11)

4.8	—	Indenture, dated as of May 19, 2003, between CenterPoint Energy and JPMorgan Chase Bank, as Trustee	CenterPoint Energy’s Form 8-K dated May 19, 2003		1-31447			4.1


					SEC File												SEC File
					or												or
Exhibit					Registration		Exhibit			Exhibit							Registration		Exhibit
Number		Description		Number		Reference			Number			Description		Report or Registration Statement		Number		Reference
4.9	—	Supplemental Indenture No. 7 to Exhibit 4.8, dated as of February 6, 2007, providing for the issuance of CenterPoint Energy’s 5.95% Senior Notes due 2017	CenterPoint Energy’s Form 10-K for the year ended December 31, 2006		1-31447			4(g	)(8)

10.1	—	Form of Performance Share Award Agreement for 20XX — 20XX Performance Cycle under the Long-Term Incentive Plan of CenterPoint Energy, Inc.	CenterPoint Energy’s Form 8-K dated February 21, 2007		1-31447			10.1			—		Form of Performance Share Award Agreement for 20XX — 20XX Performance Cycle under the Long-Term Incentive Plan of CenterPoint Energy, Inc.		CenterPoint Energy’s Form 8-K dated February 20, 2008		1-31447			10.1

10.2	—	Form of Stock Award Agreement (With Performance Goal) under the Long-Term Incentive Plan of CenterPoint Energy, Inc.	CenterPoint Energy’s Form 8-K dated February 21, 2007		1-31447			10.2			—		Form of Stock Award Agreement (With Performance Goal) under the Long-Term Incentive Plan of CenterPoint Energy, Inc.		CenterPoint Energy’s Form 8-K dated February 20, 2008		1-31447			10.2

10.3	—	Form of Stock Award Agreement (Without Performance Goal) under the Long-Term Incentive Plan of CenterPoint Energy, Inc.	CenterPoint Energy’s Form 8-K dated February 21, 2007		1-31447			10.3			—		First Amendment to CenterPoint Energy, Inc. Deferred Compensation Plan (as amended and restated effective January 1, 2003)		CenterPoint Energy’s Form 8-K dated February 20, 2008		1-31447			10.3

10.4	—	Form of Change in Control Agreement.	CenterPoint Energy’s Form 8-K dated February 21, 2007		1-31447			10.4			—		CenterPoint Energy 2005 Deferred Compensation Plan (effective January 1, 2008)		CenterPoint Energy’s Form 8-K dated February 20, 2008		1-31447			10.3

+10.5	—	First Amendment, effective January 1, 2007, to Long-Term Incentive Plan of CenterPoint Energy, Inc.

+12	—	Computation of Ratios of Earnings to Fixed Charges									—		Computation of Ratios of Earnings to Fixed Charges

+31.1	—	Rule 13a-14(a)/15d-14(a) Certification of David M. McClanahan									—		Rule 13a-14(a)/15d-14(a) Certification of David M. McClanahan

+31.2	—	Rule 13a-14(a)/15d-14(a) Certification of Gary L. Whitlock									—		Rule 13a-14(a)/15d-14(a) Certification of Gary L. Whitlock

+32.1	—	Section 1350 Certification of David M. McClanahan									—		Section 1350 Certification of David M. McClanahan

+32.2	—	Section 1350 Certification of Gary L. Whitlock									—		Section 1350 Certification of Gary L. Whitlock

+99.1	—	Items incorporated by reference from the CenterPoint Energy Form 10-K. Item 1A “Risk Factors”									—		Items incorporated by reference from the CenterPoint Energy Form 10-K. Item 1A “Risk Factors”


PART I. FINANCIAL INFORMATION

Item 1. Financial Statements		1
Condensed Statements of Consolidated Income Three Months Ended March 31, ~~2006~~2007 and ~~2007~~2008 (unaudited)		1
Condensed Consolidated Balance Sheets December 31, ~~2006~~2007 and March 31, ~~2007~~2008 (unaudited)		2
Condensed Statements of Consolidated Cash Flows Three Months Ended March 31, ~~2006~~2007 and ~~2007~~2008 (unaudited)		4
Notes to Unaudited Condensed Consolidated Financial Statements		5
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	22	23
Item 3. Quantitative and Qualitative Disclosures about Market Risk		35
Item 4. Controls and Procedures		36

PART II. OTHER INFORMATION
Item 1. Legal Proceedings	37	36
Item 1A. Risk Factors		36
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds		37
Item 4. Submission of Matters to a Vote of Security Holders		37
Item 5. Other Information	37	38
Item 6. Exhibits		38
~~First~~Articles of Amendment to ~~Long-Term Incentive Plan~~Amended and Restated Articles of Incorporation
Computation of ~~Ratio~~Ratios of Earnings to Fixed Charges
Certification of David M. McClanahan Pursuant to Rule 13a-14(a)/15d-14(a)
Certification of Gary L. Whitlock Pursuant to Rule 13a-14(a)/15d-14(a)
Certification of David M. McClanahan Pursuant to Section 1350
Certification of Gary L. Whitlock Pursuant to Section 1350
Risk Factors ~~from~~From the Form 10-K


	December 31,			March 31,			December 31,		March 31,
	2006			2007			2007		2008
Current Assets:
Cash and cash equivalents	$	127		$	60		$	129	$	70
Investment in Time Warner common stock		471			427			357		303
Accounts receivable, net		1,017			1,116			910		1,097
Accrued unbilled revenues		451			336			558		455
Natural gas inventory		305			91			395		65
Materials and supplies		94			91			95		98
Non-trading derivative assets		98			44			38		59
Prepaid expenses and other current assets		432			268			306		204

Total current assets		2,995			2,433			2,788		2,351


Property, Plant and Equipment:
Property, plant and equipment		12,567			12,822			13,250		13,332
Less accumulated depreciation and amortization		(3,363	)		(3,398	)		3,510		3,530

Property, plant and equipment, net		9,204			9,424			9,740		9,802


Other Assets:
Goodwill		1,709			1,709			1,696		1,696
Regulatory assets		3,290			3,248			2,993		2,907
Non-trading derivative assets		21			16			11		22
Notes receivable from unconsolidated affiliates								148		150
Other		414			376			496		607

Total other assets		5,434			5,349			5,344		5,382


Total Assets	$	17,633		$	17,206		$	17,872	$	17,535

	§		~~increased operating income of $31 million in our Competitive Natural Gas Sales and Services business segment;~~

	§		~~increased operating income of $26 million in our Natural Gas Distribution business segment; and~~

	§		~~decreased operating loss of $3~~to decreased operating income of $50 million in our Competitive Natural Gas Sales and Services business segment, decreased operating income of $14 million in our Electric Transmission & Distribution utility and decreased operating income of $8 million in our Natural Gas Distribution business segment. These decreases in consolidated net income were partially offset by increased operating income of $27 million in our Interstate Pipelines business segment, increased operating income of $23 million in our Field Services business segment, decreased interest expense, excluding interest on transition bonds, of $8 million due to lower amortization of deferred financing costs and increased operating income of $4 million in our Other Operations business segment.

	§		~~decreased operating income of $6 million in our Electric Transmission & Distribution business segment;~~

	§		~~decreased operating income of $5 million in our Interstate Pipelines business segment;~~

	§		~~decreased operating income of $2 million in our Field Services business segment; and~~

	§		~~increased interest expense, excluding interest on transition bonds, of $8 million due to higher borrowing levels.~~


		CENTERPOINT ENERGY, INC.
~~CENTERPOINT ENERGY, INC.~~	By:	/s/ Walter L. Fitzgerald
				Walter L. Fitzgerald
		~~By:~~	~~/s/ James S. Brian~~ ~~James S. Brian~~ Senior Vice President and Chief Accounting Officer

	•		the outcome of litigation brought by or against us;

	•		our ability to control costs;


	•		the investment performance of our employee benefit plans;

	•		our potential business strategies, including acquisitions or dispositions of assets or businesses, which we cannot assure will be completed or will have the anticipated benefits to us;

	•		acquisition and merger activities ~~in respect of~~involving us or our ~~competitors by third parties;~~competitors; and

	•		other factors we discuss in “Risk Factors” in Item 1A of Part I of our Annual Report on Form 10-K for the year ended December 31, ~~2006,~~2007, which is incorporated herein by reference, and other reports we file from time to time with the Securities and Exchange Commission.


	Three Months Ended						Three Months Ended
	March 31,						March 31,
	2006			2007			2007			2008
Revenues	$	3,077		$	3,106		$	3,106		$	3,363


Expenses:
Natural gas		2,193			2,150			2,150			2,393
Operation and maintenance		331			352			352			365
Depreciation and amortization		140			145			145			158
Taxes other than income taxes		107			106			106			111

Total		2,771			2,753			2,753			3,027

Operating Income		306			353			353			336


Other Income (Expense):
Loss on Time Warner investment		(14	)		(44	)		(44	)		(54	)
Gain on indexed debt securities		10			41			41			50
Interest and other finance charges		(115	)		(123	)		(123	)		(115	)
Interest on transition bonds		(33	)		(31	)		(31	)		(33	)
Other, net		6			6			6			13

Total		(146	)		(151	)		(151	)		(139	)


Income Before Income Taxes		160			202			202			197
Income tax expense		(72	)		(72	)		(72	)		(74	)

Net Income	$	88		$	130		$	130		$	123


Basic Earnings Per Share	$	0.28		$	0.41		$	0.41		$	0.38


Diluted Earnings Per Share	$	0.28		$	0.38		$	0.38		$	0.36


	For the Three Months Ended						For the Three Months Ended
	March 31,						March 31,
	2006			2007			2007			2008
	(in millions)						(in millions)
Net income	$	88		$	130		$	130		$	123

Other comprehensive income (loss):
Adjustment to pension and other postretirement plans		—			2
Net deferred loss from cash flow hedges		(3	)		—
Reclassification of deferred gain from cash flow hedges realized in net income		(3	)		(22	)
SFAS No. 158 adjustment (net of tax of $1 and $1)								2			2
Net deferred loss from cash flow hedges (net of tax of $5)								—			(9	)
Reclassification of deferred gain from cash flow hedges realized in net income (net of tax of $14 and $2)								(22	)		(4	)

Other comprehensive loss		(6	)		(20	)		(20	)		(11	)

Comprehensive income	$	82		$	110		$	110		$	112


(1)		Options to purchase ~~8,425,822~~3,752,647 and ~~3,752,647~~2,848,340 shares were outstanding for the three months ended March 31, ~~2006~~2007 and ~~2007,~~2008, respectively, but were not included in the computation of diluted earnings per share because the options’ exercise price was greater than the average market price of the common shares for the respective periods.


(1)		Sales to subsidiaries of RRI in the three months ended March 31, ~~2006~~2007 and ~~2007~~2008 represented approximately ~~$162~~$149 million and ~~$149~~$142 million, respectively, of CenterPoint Houston’s transmission and distribution revenues.

(2)		Included in total assets of Other Operations as of December 31, ~~2006~~2007 and March 31, ~~2007 is a~~2008 are pension ~~asset~~assets of ~~$109~~$231 million and ~~$113~~$236 million, respectively. Also included in total assets of Other Operations as of December 31, ~~2006~~2007 and March 31, ~~2007, is a~~2008, are pension related regulatory ~~asset~~assets of ~~$420~~$319 million and ~~$416~~$317 million, respectively, ~~that resulted~~resulting from the Company’s adoption of SFAS No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans — An Amendment of FASB Statements No. 87, 88, 106 and 132(R)”.


(1)		Represents the amount necessary to pay interest on the transition bonds.


	•		increases in interest expense in connection with debt refinancings and borrowings under credit facilities;

	•		various regulatory actions;

	•		the ability of RRI and its subsidiaries to satisfy their obligations as the principal customers of CenterPoint Houston and in respect of RRI’s indemnity obligations to us and our subsidiaries or in connection with the contractual obligations to a third party pursuant to which CERC is a guarantor;

	•		slower customer payments and increased write-offs of receivables due to higher gas prices or changing economic conditions;

	•		cash payments in connection with the exercise of contingent conversion rights of holders of convertible debt;

	•		the outcome of litigation brought by and against us;

	•		contributions to benefit plans;

	•		restoration costs and revenue losses resulting from natural disasters such as hurricanes; and

	•		various other risks identified in “Risk Factors” in Item 1A of our ~~2006~~2007 Form 10-K.

Large accelerated filerþ

Accelerated filero

Non-accelerated filero

Smaller reporting companyo

~~Large accelerated filer~~þ(Do not check if a smaller reporting company)

~~Accelerated filer~~o

~~Non-accelerated filer~~o